Oil and gas production handbook - Process Control and ...

OIL AND GAS
PRODUCTION
HANDBOOK
An introduction to oil and gas production
Håvard Devold
© 2006 ABB ATPA Oil and Gas
0

PREFACE
This handbook is has been compiled to give readers with an interested in the oil and
gas production industry an overview of the main processes and equipment. When I
started to search for a suitable introduction to be used for new engineers, I
discovered that much of this equipment is described in standards, equipment manuals
and project documentation. But little material was found to quickly give the reader
an overview of the entire upstream area, while still preserving enough detail to let the
engineer get an appreciation of the main characteristics and design issues.,
This book is by no means a comprehensive description on the detailed design of any
part of this process, and many details have been omitted in the interest of overview. I
have included some comments on the control issues, since that is part of my own
background. For the same reason, the description will be somewhat biased toward
the offshore installations.
The material has been compiled form various online sources as well as ABB and
customer documents. I am thankful to my colleagues in the industry for providing
valuable input, in particular Erik Solbu of Norsk Hydro for the Njord process and
valuable comments. I have included many photos to give the reader an impression
what typical facilities or equipment look like. Non-ABB photo source given below
picture other pictures and illustrations are ABB.
Edition 1.3 Oslo, June 2006
Håvard Devold
©2006 ABB ATPA Oil and Gas
Except as otherwise indicated, all materials, including but not limited to design, text, graphics,
other files, and the selection and arrangement thereof, are the copyright property of ABB, ALL
RIGHTS RESERVED. You may electronically copy and print hard-copy of this document only for
non-commercial personal use, or non-commercial use within the organization that employs you,
provided that the materials are not modified and all copyright or proprietary notices are retained.
Use of photos and graphics and references form other sources in no way promotes or endorses
these products and services and is for illustration only.
1

CONTENTS
1 Introduction....................................................................................................... 4
2 Process overview .............................................................................................. 6
2.1 Facilities .................................................................................................. 7
2.1.1 Onshore.......................................................................................... 8
2.1.2 Offshore......................................................................................... 9
2.2 Main Process Sections........................................................................... 12
2.2.1 Wellheads .................................................................................... 12
2.2.2 Manifolds/gathering..................................................................... 12
2.2.3 Separation .................................................................................... 13
2.2.4 Gas compression.......................................................................... 14
2.2.5 Metering, storage and export ....................................................... 15
2.3 Utility systems....................................................................................... 16
3 Reservoir and Wellheads ................................................................................ 17
3.1 Crude oil and Natural gas...................................................................... 17
3.1.1 Crude Oil ..................................................................................... 17
3.1.2 Natural Gas .................................................................................. 18
3.1.3 Condensates ................................................................................. 19
3.2 The Reservoir ........................................................................................ 19
3.3 Exploration and Drilling........................................................................ 21
3.4 The Well................................................................................................ 24
3.4.1 Well Casing ................................................................................. 25
3.4.2 Completion .................................................................................. 26
3.5 Wellhead ............................................................................................... 27
3.5.1 Subsea wells ................................................................................ 29
3.5.2 Injection....................................................................................... 30
3.6 Artificial Lift ......................................................................................... 30
3.6.1 Rod Pumps................................................................................... 31
3.6.2 Downhole Pumps......................................................................... 31
3.6.3 Gas Lift ........................................................................................ 32
3.6.4 Plunger Lift.................................................................................. 33
3.7 Well workover, intervention and stimulation. ....................................... 33
3.8 Unconventional sources of oil and gas.................................................. 35
3.8.1 Extra Heavy Crude ...................................................................... 35
3.8.2 Tar sands...................................................................................... 36
3.8.3 Oil Shale ...................................................................................... 36
3.8.4 Coal, Coal Gasification and Liquefaction.................................... 37
3.8.5 Methane Hydrates........................................................................ 37
3.8.6 Biofuels........................................................................................ 38
3.8.7 Hydrogen ..................................................................................... 38
4 The Oil and Gas Process................................................................................. 40
4.1 Manifolds and Gathering....................................................................... 42
2

4.1.1 Pipelines, and Risers.................................................................... 42
4.1.2 Production, test and injection manifolds...................................... 42
4.2 Separation.............................................................................................. 43
4.2.1 Test Separators and Well test....................................................... 43
4.2.2 Production separators................................................................... 43
4.2.3 Second stage separator................................................................. 45
4.2.4 Third stage separator.................................................................... 45
4.2.5 Coalescer ..................................................................................... 46
4.2.6 Electrostatic Desalter ................................................................... 46
4.2.7 Water treatment ........................................................................... 46
4.3 Gas treatment and Compression............................................................ 48
4.3.1 Heat exchangers........................................................................... 48
4.3.2 Scrubbers and reboilers................................................................ 49
4.3.3 Compressor anti surge and performance...................................... 50
4.3.4 Gas Treatment.............................................................................. 54
4.4 Oil and Gas Storage, Metering and Export ........................................... 54
4.4.1 Fiscal Metering ............................................................................ 54
4.4.2 Storage......................................................................................... 57
4.4.3 Marine Loading ........................................................................... 58
4.4.4 Pipeline terminal.......................................................................... 58
5 Utility systems ................................................................................................ 59
5.1 Control and Safety Systems .................................................................. 59
5.1.1 Process Control............................................................................ 59
5.1.2 Emergency Shutdown and Process Shutdown ............................. 62
5.1.3 Control and Safety configuration................................................. 63
5.1.4 Fire and Gas Systems................................................................... 65
5.1.5 Telemetry / SCADA .................................................................... 66
5.1.6 Condition Monitoring and Maintenance Support ........................ 67
5.1.7 Production Information Management Systems (PIMS)............... 68
5.1.8 Training Simulators ..................................................................... 69
5.2 Power generation and distribution......................................................... 69
5.3 Flare and Atmospheric Ventilation ....................................................... 71
5.4 Instrument air ........................................................................................ 72
5.5 HVAC ................................................................................................... 72
5.6 Water Systems....................................................................................... 73
5.6.1 Potable Water............................................................................... 73
5.6.2 Seawater....................................................................................... 73
5.6.3 Ballast Water ............................................................................... 73
5.7 Chemicals and Additives....................................................................... 74
5.8 Telecom................................................................................................. 77
6 Units................................................................................................................ 78
7 Acronyms........................................................................................................ 80
8 References....................................................................................................... 82
3

1 Introduction
Oil has been used for lighting purposes for many thousand years. In areas where oil
is found in shallow reservoirs, seeps of crude oil or gas may naturally develop, and
some oil could simply be collected from seepage or tar ponds. Historically, we know
of tales of eternal fires where oil and gas seeps would ignite and burn. One example
1000 B.C. is the site where the famous oracle of Delphi would be built, and 500 B.C.
Chinese were using natural gas to boil water.
But it was not until 1859 that "Colonel" Edwin Drake drilled the first successful oil
well, for the sole purpose of finding oil.
The Drake Well was located in the middle of quiet farm country in north-western
Pennsylvania, and began the international search for and industrial use of petroleum.
Photo: Drake Well Museum Collection, Titusville, PA
These wells were shallow by modern standards, often less than 50 meters, but could
give quite large production. In the picture from the Tarr Farm, Oil Creek Valley, the
Phillips well on the right was flowing initially at 4000 barrels per day in October
1861, and the Woodford well on the left came in at 1500 barrels per day in July,
4

1862. The oil was collected in the wooden tank in the foreground. Note the many
different sized barrels in the background. At this time, barrel size was not yet
standardized, which made terms like "Oil is selling at $5 per barrel" very confusing
(today a barrel is 159 liters, see units at the back). But even in those days,
overproduction was an issue to be avoided. When the “Empire well” was completed
in September 1861, it gave 3,000 barrels per day, flooding the market, and the price
of oil plummeted to 10 cents a barrel.
Soon, oil had replaced most other fuels for mobile use. The automobile industry
developed at the end of the 19 th century, and quickly adopted the fuel. Gasoline
engines were essential for designing successful aircraft. Ships driven by oil could
move up to twice as fast as their coal fired counterparts, a vital military advantage.
Gas was burned off or left in the ground.
Despite attempts at gas transportation as far back as 1821, it was not until after the
World War II that welding techniques, pipe rolling, and metallurgical advances
allowed for the construction of reliable long distance pipelines, resulting in a natural
gas industry boom. At the same time the petrochemical industry with its new plastic
materials quickly increased production. Even now gas production is gaining market
share as LNG provides an economical way of transporting the gas from even the
remotest sites.
With oil prices of 50 dollars per barrel or more, even more difficult to access sources
become economically interesting. Such sources include tar sands in Venezuela and
Canada as well as oil shales. Synthetic diesel (syndiesel) from natural gas and
biological sources (biodiesel, ethanol) have also become commercially viable. These
sources may eventually more than triple the potential reserves of hydrocabon fuels.
5

2 Process overview
The following figure gives a simplified overview of the typical oil and gas
production process
Production
Wellheads
Production
and Test
Manifolds
LP
Gas compressors
HP
Metering and
storage
Gas
Meter
Export
Pig
Launcher
Gas
Pipeline
Production Separators
Pig
Launcher
Oil
Pipeline
1 stage
Tanker
Loading
2 stage
ø
Crude
pump
Oil
Meter
Water treatment
Test Separator
Oil Storage
Drilling
Utility systems (selected)
Injection
wells
Injection
manifold
Power Generation
Water injection
pump
Mud and Cementing
Instrument Air
Gas injection
compressor
Potable Water
Firefighting
systems
HVAC
Figure 1 Oil and Gas production overview
6

Today oil and gas is produced in almost every part of the world, from small 100
barrel a day small private wells, to large bore 4000 barrel a day wells; In shallow 20
meters deep reservoirs to 3000 meter deep wells in more than 2000 meters water
depth; In 10.000 dollar onshore wells to 10 billion dollar offshore developments.
Despite this range many parts of the process is quite similar in principle.
At the left side, we find the wellheads. They feed into production and test manifolds.
In a distributed production system this would be called the gathering system. The
remainder of the figure is the actual process, often called the Gas Oil Separation
Plant (GOSP). While there are oil or gas only installations, more often the wellstream
will consist of a full range of hydrocarbons from gas (methane, butane,
propane etc.), condensates (medium density hydro-carbons) to crude oil. With this
well flow we will also get a variety of non wanted components such as water, carbon
dioxide, salts, sulfur and sand. The purpose of the GOSP is to process the well flow
into clean marketable products: oil, natural gas or condensates. Also included are a
number of utility systems, not part of the actual process, but providing energy, water,
air or some other utility to the plant.
2.1 Facilities
Figure 2 Oil and Gas production facilities
7

2.1.1 Onshore
Onshore production is economically
viable from a few tens of barrels a day
upwards. Oil and gas is produced from
several million wells world-wide. In
particular, a gas gathering network can
become very large, with production from
hundreds of wells, several hundred
kilometers/miles apart, feeding through a
gathering network into a processing plant.
The picture shows a well equipped with a
sucker rod pump (donkey pump) often
associated with onshore oil production.
However, as we shall see later, there are
many other ways of extracting oil from a
non-free flowing well
For the smallest reservoirs, oil is simply collected in a holding tank and collected at
regular intervals by tanker truck or railcar to be processed at a refinery.
But onshore wells in oil rich areas are also
high capacity wells with thousands of
barrels per day, connected to a 1.000.000
barrel a day gas oil separation plant
(GOSP). Product is sent from the plant by
pipeline or tankers. The production may
come from many different license owners.
Metering and logging of individual wellstreams
into the gathering network are
important tasks...
Recently, very heavy crude, tar sands and
oil shales have become economically
extractible with higher prices and new
technology. Heavy crude may need
heating and diluent to be extracted, tar
sands have lost their volatile compounds
and are strip mined or could be extracted
with steam. It must be further processed to
8

separate bitumen from the sand. These unconventional of reserves may contain more
than double the hydrocarbons found in conventional reservoirs. Photo: Energyprobe.org
cp file
2.1.2 Offshore
Offshore, depending on size and water depth, a whole range of different structures
are used. In the last few years, we have seen pure sea bottom installations with
multiphase piping to shore and no offshore topside structure at all. Replacing
outlying wellhead towers, deviation drilling is used to reach different parts of the
reservoir from a few wellhead cluster locations. Some of the common offshore
structures are:
Shallow water complex,
characterized by a several
independent platforms
with different parts of the
process and utilities linked
with gangway bridges.
Individual platforms will
be described as Wellhead
Platform, Riser Platform,
Processing Platform,
Accommodations
Platform and Power
Generation Platform. The
picture shows the Ekofisk Field Centre by
Phillips petroleum. Typically found in water
depths up to 100 meters. Photo: Conoco Phillips
Gravity Base. Enormous concrete fixed structures
placed on the bottom, typically with oil storage
cells in the “skirt” that rests on the sea bottom.
The large deck receives all parts of the process
and utilities in large modules. Typical for 80s and
90s large fields in 100 to 500 water depth. The
concrete was poured at an at shore location, with
enough air in the storage cells to keep the
structure floating until tow out and lowering onto
the seabed. The picture shows the world’s largest
GBS platform, the Troll A during construction.
Photo Statoil ASA
9

Compliant towers are much like fixed platforms. They consist of a narrow tower,
attached to a foundation on the seafloor and extending up to the platform. This tower
is flexible, as opposed to the relatively rigid legs of a fixed platform. This flexibility
allows it to operate in much deeper water, as it can 'absorb'much of the pressure
exerted on it by the wind and sea. Compliant towers are used between 500 and 1000
meters water depth.
Floating production, where all topside systems are located on a floating structure
with dry or subsea wells. Some floaters are:
FPSO: Floating
Production,
Storage and
Offloading.
Typically a
tanker type hull
or barge with
wellheads on a
turret that the
ship can rotate
freely around (to
point into wind,
waves or
current). The turret has wire rope and chain connections to several anchors
(position mooring - POSMOR), or it can be dynamically positioned using
thrusters (dynamic positioning – DYNPOS). Water depths 200 to 2000 meters.
Common with subsea wells. The main
process is placed on the deck, while the hull
is used for storage and offloading to a
shuttle tanker. May also be used with
pipeline transport.
A Tension Leg Platform (TLP) consists of a
structure held in place by vertical tendons
connected to the sea floor by pile-secured
templates. The structure is held in a fixed
position by tensioned tendons, which
provide for use of the TLP in a broad water
depth range up to about 2000m. Limited
vertical motion. The tendons are constructed
as hollow high tensile strength steel pipes
that carry the spare buoyancy of the
structure and ensure limited vertical motion.
A variant is Seastar platforms which are
10

miniature floating tension leg platforms, much like the semi submersible type,
with tensioned tendons.
SPAR: The SPAR consists
of a single tall floating
cylinder hull, supporting a
fixed deck. The cylinder
however does not extend all
the way to the seafloor, but
instead is tethered to the
bottom by a series of cables
and lines. The large cylinder
serves to stabilize the
platform in the water, and
allows for movement to
absorb the force of potential
hurricanes. Spars can be quite large and are used for water depths from 300 and
up to 3000 meters. SPAR is not an acronym, but refers to its likeness with a
ship’s spar. Spars can support dry completion wells, but is more often used with
subsea wells.
Subsea production systems are wells located on the sea floor, as opposed to at the
surface. Like in a floating production system, the petroleum is extracted at the
seafloor, and then can be 'tied-back'to an already existing production platform or
even an onshore facility, limited by horizontal distance or “offset”. The well is
drilled by a moveable rig and the extracted oil and natural gas is transported by
undersea pipeline and riser to a processing facility. This allows one strategically
placed production platform to service many wells over a reasonably large area.
Subsea systems are typically in use at depths of 7,000 feet or more, and do not have
the ability to drill, only to extract and transport. Drilling and completeion is
performed from a surface rig. Horizontal offsets up to 250 kilometers, 150 miles are
currently possible. Photo:Norsk Hydro ASA
11

2.2 Main Process Sections
We will go through each section in detail in the following chapters. The summary
below is an introductory short overview of each section
2.2.1 Wellheads
The wellhead sits on top of the actual oil or gas well leading down to the reservoir. A
wellhead may also be an injection well, used to inject water or gas back into the
reservoir to maintain pressure and levels to maximize production.
Once a natural gas or oil
well is drilled, and it has
been verified that
commercially viable
quantities of natural gas
are present for
extraction, the well must
be 'completed'to allow
for the flow of
petroleum or natural gas
out of the formation and
up to the surface. This
process includes
strengthening the well
hole with casing,
evaluating the pressure
and temperature of the formation, and then installing the proper equipment to ensure
an efficient flow of natural gas out of the well. The well flow is controlled with a
choke.
We differentiate between dry completion with is either onshore or on the deck of an
offshore structure, and Subsea completions below the surface. The wellhead
structure, often called a Christmas tree, must allow for a number of operations
relating to production and well workover. Well workover refers to various
technologies for maintaining the well and improving its production capacity.
2.2.2 Manifolds/gathering
Onshore, the individual well streams are brought into the main production facilities
over a network of gathering pipelines and manifold systems. The purpose of these is
to allow set up of production “well sets” so that for a given production level, the best
12

eservoir utilization, well flow composition (gas, oil, waster) etc. can be selected
from the available wells.
For gas gathering systems, it is common to meter the individual gathering lines into
the manifold as shown on the illustration. For multiphase (combination of gas, oil
and water) flows, the high cost of multiphase flow meters often lead to the use of
software flow rate estimators that use well test data to calculate the actual flow.
Offshore, the dry completion
wells on the main field
centre feed directly into
production manifolds, while
outlying wellhead towers
and subsea installations feed
via multiphase pipelines
back to the production risers.
Risers are the system that
allow a pipeline to “rise” up
to the topside structure. For
floating or structures, this
involves a way to take up
weight and movement. For
heavy crude and in arctic
areas, diluents and heating may be needed to reduce viscosity and allow flow.
2.2.3 Separation
Some wells have pure gas
production which can be
taken directly to gas
treatment and/or
compression. More often,
the well gives a combination
of gas, oil and water and
various contaminants which
must be separated and
processed. The production
separators come in many
forms and designs, with the
classical variant being the
gravity separator.
13

In gravity separation the well flow is fed into a horizontal vessel. The retention
period is typically 5 minutes, allowing the gas to bubble out, water to settle at the
bottom and oil to be taken out in the middle. The pressure is often reduced in several
stages (high pressure separator, low pressure separator etc.) to allow controlled
separation of volatile components. A sudden pressure reduction might allow flash
vaporization leading to instabilities and safety hazards. Photo: JL Bryan Oilfield Equipment
2.2.4 Gas compression
Gas from a pure natural gas wellhead might have sufficient pressure to feed directly
into a pipeline transport system. Gas from separators has generally lost so much
pressure that it must be recompressed to be transported. Turbine compressors gain
their energy by using up a small proportion of the natural gas that they compress.
The turbine itself serves to operate a centrifugal compressor, which contains a type
of fan that compresses and pumps the natural gas through the pipeline. Some
compressor stations are operated by using an electric motor to turn the same type of
centrifugal compressor. This type of compression does not require the use of any of
the natural gas from
the pipe; however it
does require a
reliable source of
electricity nearby.
The compression
includes a large
section of
associated
equipment such as
scrubbers
(removing liquid
droplets) and heat
exchangers, lube oil
treatment etc.
Whatever the source of the natural gas, once separated from crude oil (if present) it
commonly exists in mixtures with other hydrocarbons; principally ethane, propane,
butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen
sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds.
Natural gas processing consists of separating all of the various hydrocarbons and
fluids from the pure natural gas, to produce what is known as 'pipeline quality'dry
natural gas. Major transportation pipelines usually impose restrictions on the make-
14

up of the natural gas that is allowed into the pipeline. That means that before the
natural gas can be transported it must be purified.
Associated hydrocarbons, known as 'natural gas liquids'(NGL) ar used as raw
materials for oil refineries or petrochemical plants, and as sources of energy.
2.2.5 Metering, storage and export
Most plants do not allow local gas storage, but oil is often stored before loading on a
vessel, such as a shuttle tanker taking the oil to a larger tanker terminal, or direct to
crude carrier. Offshore
production facilities
without a direct pipeline
connection generally
rely on crude storage in
the base or hull, to allow
a shuttle tanker to
offload about once a
week. A larger
production complex
generally has an
associated tank farm
terminal allowing the
storage of different
grades of crude to take
up changes in demand, delays in transport etc.
Metering stations allow operators to monitor and manage the natural gas and oil
exported from the
production installation.
These metering stations
employ specialized
meters to measure the
natural gas or oil as it
flows through the
pipeline, without
impeding its movement.
This metered volume
represents a transfer of
ownership from a
producer to a customer
15

(or another division within the company) and is therefore called Custody Transfer
Metering. It forms the basis for invoicing sold product and also for production taxes
and revenue sharing between partners and accuracy requirements are often set by
governmental authorities.
Typically the metering installation consists of a number of meter runs so that one
meter will not have to handle the full capacity range, and associated prover loops so
that the meter accuracy can be tested and calibrated at regular intervals.
Pipelines can measure
anywhere from 6 to 48
inches in diameter. In
order to ensure the
efficient and safe
operation of the
pipelines, operators
routinely inspect their
pipelines for corrosion
and defects. This is
done through the use of
sophisticated pieces of
equipment known as
pigs. Pigs are intelligent
robotic devices that are propelled down pipelines to evaluate the interior of the pipe.
Pigs can test pipe thickness, and roundness, check for signs of corrosion, detect
minute leaks, and any other defect along the interior of the pipeline that may either
impede the flow of gas, or pose a potential safety risk for the operation of the
pipeline. Sending a pig down a pipeline is fittingly known as 'pigging'the pipeline.
The export facility must contain equipment to safely insert and retrieve pigs form the
pipeline as well as depressurization, referred to as pig launchers and pig receivers
Loading on tankers involve loading systems, ranging from tanker jetties to
sophisticated single point mooring and loading systems that allow the tanker to dock
and load product even in bad weather.
2.3 Utility systems
Utility systems are systems which does not handle the hydrocarbon process flow, but
provides some utility to the main process safety or residents. Depending on the
location of the installation, many such functions may be available from nearby
infrastructure (e.g. electricity). But many remote installations must be fully self
sustainable and thus must generate their own power, water etc.
16

3 Reservoir and Wellheads
There are three main types of conventional wells. The most common well is an oil
well with associated gas. Natural gas wells are wells drilled specifically for natural
gas, and contain little or no oil. Condensate wells are wells that contain natural gas,
as well as a liquid condensate. This condensate is a liquid hydrocarbon mixture that
is often separated from the natural gas either at the wellhead, or during the
processing of the natural gas. Depending on the type of well that is being drilled,
completion may differ slightly. It is important to remember that natural gas, being
lighter than air, will naturally rise to the surface of a well. Because of this, in many
natural gas and condensate wells, lifting equipment and well treatment are not
necessary, while for oil wells many types of artificial lift might be installed,
particularly as the reservoir pressure declines during years of production.
3.1 Crude oil and Natural gas
3.1.1 Crude Oil
Crude Oil is a complex mixture consisting of up to 200 or more different organic
compounds, mostly hydrocarbons. Different crude contain different combinations
and concentrations of these various compounds. The API (American petroleum
institute) gravity of a particular crude is merely a measure of its specific gravity, or
density. The higher the API number, expressed as degrees API, the less dense
(lighter, thinner) the crude. Conversely, the lower the degrees API, the more dense
(heavier, thicker) the crude. Crude from different fields and from different
formations within a field can be similar in composition or be significantly different.
In addition to API grade and hydrocarbons, crude is characterized for other nonwanted
elements like sulfur which is regulated and needs to be removed.
Crude oil API gravities typically range from 7 to 52 corresponding to about 970
kg/m 3 to 750 kg/m 3 , but most fall in the 20 to 45 API gravity range. Although light
crude (i.e., 40-45 degree API) is good, lighter crude (i.e., 46 degree API and above)
is not necessarily better for a typical refinery. Looking at the chemical composition
of crude, as the crude gets lighter than 40-45 degrees API, it contains shorter
molecules, or less of the desired compounds useful as high octane gasoline and
diesel fuel, the production of which most refiners try to maximize. Likewise, as
crude gets heavier than 35 degrees API, it contains longer and bigger molecules that
are not useful as high octane gasoline and diesel fuel without further processing.
17

For crude that have undergone detailed physical and chemical property analysis, the
API gravity can be used as a rough index of the quality of the crude of similar
composition as they naturally occur (that is, without adulteration, mixing, blending,
etc.). When crude of different type and quality are mixed, or when different
petroleum components are mixed, API gravity cannot be used meaningfully for
anything other than a measure of the density of the fluid.
For example, consider a barrel of tar that is dissolved in 3 barrels of naphtha (lighter
fluid) to produce 4 barrels of a 40 degree API mixture. When this 4-barrel mixture is
fed to a distillation column at the inlet to a refinery, one barrel of tar plus 3 barrels of
lighter fluid is all that will come out of the still. On the other hand, 4 barrels of a
naturally occurring 40 degree API South Louisiana Sweet crude when fed to the
distillation column at the refinery could come out of the still as 1.4 barrels of
gasoline and naphtha, 0.6 barrels of kerosene (jet fuel), 0.7 barrels of diesel fuel, 0.5
barrels of heavy distillate, 0.3 barrels of lubricating stock, and 0.5 barrels of
residuum (tar).
The figure to the right
illustrates weight percent
distributions of three
different hypothetical
petroleum stocks that
could
be fed to a refinery with
catalytic cracking
capacity. The chemical
composition is generalized
by the carbon number
which is the number of
carbon atoms in each
molecule. The medium
blend is desired because it
has the composition that will yield the highest output of high octane gasoline and
diesel fuel in the cracking refinery. Though the heavy stock and the light stock could
be mixed to produce a blend with the same API gravity as the medium stock, the
composition of the blend would be far different from the medium stock, as the figure
indicates. Heavy crude can be processed in a refinery by cracking and reforming that
reduces the carbon number to increase the high value fuel yield.
3.1.2 Natural Gas
The natural gas used by consumers is composed almost entirely of methane.
However, natural gas found at the wellhead, although still composed primarily of
18

methane, is by no means as pure. Raw natural gas comes from three types of wells:
oil wells, gas wells, and condensate wells. Natural gas that comes from oil wells is
typically termed 'associated gas'. This gas can exist separate from oil in the formation
(free gas), or dissolved in the crude oil (dissolved gas). Natural gas from gas and
condensate wells, in which there is little or no crude oil, is termed 'non associated
gas'. Gas wells typically produce raw natural gas by itself, while condensate wells
produce free natural gas along with a semi-liquid hydrocarbon condensate. Whatever
the source of the natural gas, once separated from crude oil (if present) it commonly
exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and
pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S),
carbon dioxide, helium, nitrogen, and other compounds.
Natural gas processing consists of separating all of the various hydrocarbons and
fluids from the pure natural gas, to produce what is known as 'pipeline quality'dry
natural gas. Major transportation pipelines usually impose restrictions on the makeup
of the natural gas that is allowed into the pipeline and measure energy content in
kJ/kg (also called calorific value or wobbe index).
3.1.3 Condensates
While the ethane, propane, butane, and pentanes must be removed from natural gas,
this does not mean that they are all 'waste products. In fact, associated hydrocarbons,
known as 'natural gas liquids'(NGL) can be very valuable by-products of natural gas
processing. NGL include ethane, propane, butane, iso-butane, and natural gasoline.
These NGLs are sold separately and have a variety of different uses; raw materials
for oil refineries or petrochemical plants, as sources of energy, and for enhancing oil
recovery in oil wells,. Condensates are also useful as diluent for heavy crude, see
below.
3.2 The Reservoir
The oil and gas bearing
structure is typically a
porous rock such as
sandstone or washed out
limestone. The sand might
have been laid down as
desert sand dunes or
seafloor. Oil and gas
deposits form as organic
material (tiny plants and
animals) deposited in earlier
geological periods, typically
19

100 to 200 million years ago, under ,over or with the sand or silt, is transformed by
high temperature and pressure into hydrocarbons.
For an oil reservoir to form, porous rock needs to be covered by a non porous layer
such as salt, shale, chalk or mud rock that can prevent the hydrocarbons from leaking
out of the structure. As rock structures become folded and uplifted as a result of
tectonic movements, the hydrocarbons migrates out of the deposits and upward in
porous rocks and collects in crests under the non permeable rock, with gas at the top,
then oil and fossil water at the bottom. . Ill: UKOOA
This process goes on continuously, even today. However, an oil reservoir matures in
the sense that a too young formation may not yet have allowed the hydrocarbons to
form and collect. A young reservoir (e.g. 60 million years) often has heavy crude,
less than 20 API. In some areas, strong uplift and erosion and cracking of rock above
have allowed the hydrocarbons to leak out, leaving heavy oil reservoirs or tar pools.
Some of the world’s largest oil deposits are tar sands where the volatile compounds
have evaporated from shallow sandy formations leaving huge volumes of bitumen
soaked sands. These are often exposed at the surface, and could be strip mined, but
must be separated from the sand with hot water, steam and diluents and further
processed with cracking and reforming in a refinery) to improve its fuel yield.
20

The oil and gas is pressurized in the
pores of the porous formation rock.
Ill: UKOOA When a well is drilled
into the reservoir structure, the
hydrostatic formation pressure
drives the hydrocarbons out of the
rock and up into the well. When the
well flows, gas, oil and water is
extracted, and the levels will shift
as the reservoir is depleted. The
challenge is to plan the drilling so
that the reservoir utilization can be
maximized.
Seismic data and advanced
visualization 3D models are used to
plan the extraction. Still the
average recovery rate is 40%,
leaving 60% of the hydrocarbons
trapped in the reservoir. The best
reservoirs with advanced Enhanced
Oil Recovery (EOR) allow up to 70%. Reservoirs can be quite complex, with many
folds and several layers of hydrocarbon bearing rock above each other (in some areas
more than 10). Modern wells are drilled with large horizontal offsets to reach
different parts of the structure and with multiple completions so that one well can
produce from several locations. Ill: UKOOA
3.3 Exploration and Drilling
When 3D seismic has been
completed, it is time to drill the
well. Normally dedicated drilling
rigs either on mobile onshore
units or offshore floating rigs are
used. Larger production
platforms may also have their
own production drilling
equipment.
The main components of the
drilling rig are the Derrick, Floor,
Drawworks, Drive and Mud
Handling. The control and power
21

can be hydraulic or electric.
Earlier pictures of Drillers and Roughnecks working with rotary tables (bottom
drives) are now replaced with top drive and semi automated pipe handling on larger
installations. The hydraulic or electric top drive hangs from the derrick crown and
gives pressure and rotational torque to the drill string. The whole assembly is
controlled by the drawworks. Photo: Puna Geothermal Venture
The Drill String is assembled from pipe segments about 30 meters (100 feet) long
normally with conical inside threads at one end and outside at the other. As each 30
meter segment is drilled, the drive is disconnected and a new pipe segment inserted
in the string. A cone bit is used to dig into the rock. Different cones are used for
different types of rock and at different stages of the well. The picture shows roller
cones with inserts (on the left); other bits are PDC (polycrystalline diamond
compact, on the right) and Diamond Impregnated. Photo: Kingdream PLC
As the well is sunk into the
ground, the weight of the
drill string increases and
might reach 500 metric tons
or more for a 3000 meter
deep well. The drawwork
and top drive must be
precisely controlled not to
overload and break the drill
string or the cone. Typical
values are 50kN force on the
bit and a torque of 1-1.5
kNm at 40-80 RPM for an 8
inch cone. ROP (Rate of
Penetration) is very
dependant on depth and
could be as much as 20
meters per hour for shallow
sandstone and dolomite
(chalk) and as low as 1
m/hour on deep shale rock
and granite.
Directional drilling is
intentional deviation of a
well bore from the vertical.
It is often necessary to drill
22

at an angle from the vertical to reach different parts of the formation. Controlled
directional drilling makes is possible to reach subsurface areas laterally remote from
the point where the bit enters the earth. It often involves the use of a drill motor
driven by mud pressure mounted directly on the cone (Mud Motor, Turbo Drill, and
Dyna-Drill), whipstocks: a steel casing that will bend between the drill pipe and
cone, or other deflecting rods. Also used for horizontal wells and multiple
completions, where one well may split into several bores. A well which has sections
more than 80 degrees from the vertical is called a horizontal well. Modern wells are
drilled with large horizontal offsets to reach different parts of the structure and
achieve higher production. The world record is more than 15 kilometers. Multiple
completions allows production from several locations.
Wells can be any depth from almost at the surface to a depth of more than 6000
meters. The oil and gas typically formed at 3000-4000 meters depth, but the
overlying rock can since have eroded away. The pressure and temperature generally
increases with increasing depth, so that deep wells can have more than 200 deg C
temperature and 90 MPa pressure (900 times atmospheric pressure), equivalent to the
hydrostatic pressure set by the distance to the surface., The weight of the oil in the
production string reduces the wellhead pressure. Crude oil has a specific weight of
790 to 970 kg per cubic meter. For a 3000 meter deep well with 30 MPa downhole
pressure and normal crude oil at 850 kg/m 3 , the wellhead static pressure would only
be around 4,5 MPa. During production the pressure would go down further due
resistance to flow in the reservoir and well.
The mud enters though the drill pipe, through the cone and rises in the uncompleted
well. The Mud serves several purposes:
• Bring rock shales (fragments of rock) up to the surface
• Clean and Cool the cone
• Lubricate the drill pipe string and Cone
• Fibrous particles attach to the well surface to bind solids
• Mud weight should balance the downhole pressure to avoid leakage of gas
and oil. Often, the well will drill though smaller pockets of hydrocarbons
which may cause “a blow out” if the mud weight cannot balance the
pressure. The same might happen when drilling into the main reservoir.
To prevent an uncontrolled blow out, a subsurface safety valve is often installed.
This valve has enough closing force to seal the well and cut the drill string in an
uncontrollable blow-out situation. However unless casing is already also in place,
hydrocarbons may also leave though other cracks in the in the well and rise to the
surface through porpus or cracked rock. In addtion to fire and polution hazards,
dissolved gas in seawater rising under a floating structure significantly reduces
buoyancy.
23

The mud mix is a
specialist brew designed
to match the desired flow
viscosity, lubrication
properties and specific
gravity. Mud is a common
name used for all kinds of
fluids used in drilling
completion and workover,
It can be Oil Base, Water
Base or Synthetic and
consists of powdered clays
such as bentonite, Oil,
Water and various
additives and chemicals such as caustic soda, barite (sulphurous mineral), lignite
(brown coal), polymers and emulsifiers. Photo: OSHA.gov
A special high density mud called Kill Fluid is used to shut down a well for
workover.
Mud is recirculated. The coarse rock shales are separated in a shale shaker, the mud
could then pass though finer filters and recalibrated with new additives before
returning to the mud holding tanks
3.4 The Well
When the well
has been drilled,
it must be
completed.
Completing a
well consists of a
number of steps;
installing the well
casing,
completing the
well, installing
the wellhead, and
installing lifting
equipment or
treating the
formation should
that be required.
24

3.4.1 Well Casing
Installing well casing is an important part of the drilling and completion process.
Well casing consists of a series of metal tubes installed in the freshly drilled hole.
Casing serves to strengthen the sides of the well hole, ensure that no oil or natural
gas seeps out of the well hole as it is brought to the surface, and to keep other fluids
or gases from seeping into the formation through the well. A good deal of planning is
necessary to ensure that the proper casing for each well is installed. Types of casing
used depend on the subsurface characteristics of the well, including the diameter of
the well (which is dependent on the size of the drill bit used) and the pressures and
temperatures experienced throughout the well. In most wells, the diameter of the
well hole decreases the deeper it is drilled, leading to a type of conical shape that
must be taken into account when installing casing. The casing is normally cemented
in place. Ill: wikipedia.org
There are five different types of well casing. They include:
• Conductor casing, which is usually no more than 20 to 50 feet long, is
installed before main drilling to prevent the top of the well from caving in
and to help in the process of circulating the drilling fluid up from the bottom
of the well.
• Surface casing is the next type of casing to be installed. It can be anywhere
from 100 to 400 meters long, and is smaller in diameter than the conductor
casing and fits inside the conductor casing. The primary purpose of surface
casing is to protect fresh water deposits near the surface of the well from
being contaminated by leaking hydrocarbons or salt water from deeper
underground. It also serves as a conduit for drilling mud returning to the
surface, and helps protect the drill hole from being damaged during drilling.
• Intermediate casing is usually the longest section of casing found in a well.
The primary purpose of intermediate casing is to minimize the hazards that
come along with subsurface formations that may affect the well. These
include abnormal underground pressure zones, underground shales, and
formations that might otherwise contaminate the well, such as underground
salt-water deposits. Liner strings are sometimes used instead of intermediate
casing. Liner strings are usually just attached to the previous casing with
'hangers', instead of being cemented into place and is thus less permanent
• Production casing, alternatively called the 'oil string'or 'long string', is
installed last and is the deepest section of casing in a well. This is the casing
that provides a conduit from the surface of the well to the petroleum
producing formation. The size of the production casing depends on a
number of considerations, including the lifting equipment to be used, the
25

number of completions required, and the possibility of deepening the well at
a later time. For example, if it is expected that the well will be deepened at a
later date, then the production casing must be wide enough to allow the
passage of a drill bit later on. It is also instrumental in preventing blowouts,
allowing the formation to be 'sealed'from the top should dangerous pressure
levels be reached.
Once the casing is installed, tubing is inserted inside the casing, from the opening
well at the top, to the formation at the bottom. The hydrocarbons that are extracted
run up this tubing to the surface. The production casing is typically 5 to 28 cm (2 -11
in) with most production wells being 6 in or more. Production depends on reservoir,
bore, pressure etc. and could be less than 100 barrels a day to several thousand
barrels per day. (5000 bpd is about 555 liters/minute). A packer is used between
casing and tubing at the bottom of the well.
3.4.2 Completion
Well completion commonly refers to the process of finishing a well so that it is ready
to produce oil or natural gas. In essence, completion consists of deciding on the
characteristics of the intake portion of the well in the targeted hydrocarbon
formation. There are a number of types of completions, including:
• Open hole completions are the most basic type and are only used in very
competent formations, which are unlikely to cave in. An open hole
completion consists of simply running the casing directly down into the
formation, leaving the end of the piping open, without any other protective
filter.
• Conventional perforated completions consist of production casing being run
through the formation. The sides of this casing are perforated, with tiny
holes along the sides facing the formation, which allows for the flow of
hydrocarbons into the well hole, but still provides a suitable amount of
support and protection for the well hole. In the past, 'bullet perforators'were
used. These were essentially small guns lowered into the well that sent off
small bullets to penetrate the casing and cement. Today, 'jet perforating'is
preferred. This consists of small, electrically ignited charges that are
lowered into the well. When ignited, these charges poke tiny holes through
to the formation, in the same manner as bullet perforating.
• Sand exclusion completions are designed for production in an area that
contains a large amount of loose sand. These completions are designed to
allow for the flow of natural gas and oil into the well, but at the same time
prevent sand from entering the well. The most common method of keeping
26

sand out of the well hole are screening, or filtering systems. Both of these
types of sand barriers can be used in open hole and perforated completions.
• Permanent completions are those in which the completion, and wellhead,
are assembled and installed only once. Installing the casing, cementing,
perforating, and other completion work is done with small diameter tools to
ensure the permanent nature of the completion. Completing a well in this
manner can lead to significant cost savings compared to other types
• Multiple zone completion is the practice of completing a well such that
hydrocarbons from two or more formations may be produced
simultaneously, without mixing with each other. For example, a well may
be drilled that passes through a number of formations on its way deeper
underground, or alternately, it may be efficient in a horizontal well to add
multiple completions to drain the formation most effectively. When it is
necessary to separate different completions, hard rubber 'packing'
instruments are used to maintain separation.
• Drainhole completions are a form of horizontal or slant drilling. This type
of completion consists of drilling out horizontally into the formation from a
vertical well, essentially providing a 'drain'for the hydrocarbons to run
down into the well. These completions are more commonly associated with
oil wells than with natural gas wells.
3.5 Wellhead
Wellheads can be Dry or Subsea completion.
Dry Completion means that the well is onshore
on the topside structure on an offshore
installation. Subsea wellheads are located under
water on a special sea bed template.
The wellhead consists of the pieces of equipment
mounted at the opening of the well to regulate
and monitor the extraction of hydrocarbons from
the underground formation. It also prevents
leaking of oil or natural gas out of the well, and
prevents blowouts due to high pressure
formations. Formations that are under high
pressure typically require wellheads that can
withstand a great deal of upward pressure from
the escaping gases and liquids. These wellheads
must be able to withstand pressures of up to 140
MPa (1400 Bar). The wellhead consists of three
27

components: the casing head, the tubing head, and the 'Christmas tree'Photo: Vetco
international
A typical Christmas tree
composed of a master gate
valve, a pressure gauge, a wing
valve, a swab valve and a
choke is shown here. The
Christmas tree may also have a
number of check valves. The
functions of these devices are
explained in the following
paragraphs. Ill: Vetco international
At the bottom we find the
Casing Head and casing
Hangers. The casing will be
screwed, bolted or welded to
the hanger. Several valves and
plugs will normally be fitted to
give access to the casing. This
will permit the casing to be
opened, closed, bled down,
and, in some cases, allow the
flowing well to be produced
through the casing as well as
the tubing. The valve can be
used to determine leaks in
casing, tubing or the packer,
and will also be used for lift
gas injection into the casing.
The tubing hanger (also called donut) is used to position the tubing correctly in the
well. Sealing also allows Christmas tree removal with pressure in the casing.
Master gate valve. The master gate valve is a high quality valve. It will provide full
opening, which means that it opens to the same inside diameter as the tubing so that
specialized tools may be run through it. It must be capable of holding the full
pressure of the well safely for all anticipated purposes. This valve is usually left fully
open and is not used to control flow.
28

The pressure gauge. The minimum instrumentation is a pressure gauge placed
above the master gate valve before the wing valve. In addition other instruments
such as temperature will normally be fitted.
The wing valve. The wing valve can be a gate valve, or ball valve. When shutting in
the well, the wing gate or valve is normally used so that the tubing pressure can be
easily read.
The swab valve. The swab valve is used to gain access to the well for wireline
operations, intervention and other workover procedures (see below), on top of it is a
tree adapter and cap that will mate with various equipment.
The variable flow choke valve. The variable flow choke valve is typically a large
needle valve. Its calibrated opening is adjustable in 1/64 inch increments (called
beans). High-quality steel is used in order to withstand the high-speed flow of
abrasive materials that pass through the choke, usually for many years, with little
damage except to the dart or seat. If a variable choke is not required, a less expensive
positive choke is normally installed on smaller wells. This has a built in restriction
that limits flow when the wing valve is fully open.
This is a vertical tree. Christmas trees can also be horizontal, where the master,
wing and choke is on a horizontal axis. This reduces the height and may allow easier
intervention. Horizontal trees are especially used on subsea wells.
3.5.1 Subsea wells
Subsea wells are essentially the same
as dry completion wells. However,
mechanically they are placed in a
Subsea structure (template) that
allows the wells to be drilled and
serviced remotely from the surface,
and protects from damage e.g. from
trawlers. The wellhead is placed in a
slot in the template where it mates to
the outgoing pipeline as well as
hydraulic and electric control signals.
Ill: Statoil
Control is from the surface where a hydraulic power unit (HPU) provides hydraulic
power to the subsea installation via an umbilical. The umbilical is a composite cable
containing tension wires, hydraulic pipes, electrical power and control and
communication signals. A control pod with inert gas and/or oil protection contains
29

control electronics, and
operates most equipment
Subsea via hydraulic
switches. More complex
Subsea solutions may
contain subsea
separation/stabilization
and electrical multiphase
pumping. This may be
necessary if reservoir
pressure is low, offset
(distance to main facility)
is long or there are flow assurance problems so that the gas and liquids will not
stably flow to the surface.
Product is piped back through pipelines and risers to the surface. The main choke
may be located topside.
3.5.2 Injection
Wells are also divided into production and injection wells. The former is for
production of oil and gas, injection wells is drilled to inject gas or water into the
reservoir. The purpose of injection is to maintain overall and hydrostatic reservoir
pressure and force the oil toward the production wells. When injected water reaches
the production well, this is called injected water break through. Special logging
instruments, often based on radioactive isotopes added to injection water, are used to
detect breakthrough.
Injection wells are fundamentally the same as production wellheads other than the
direction of flow and therefore the mounting of some directional component such as
the choke.
3.6 Artificial Lift
Production wells are free flowing or lifted. A free flowing oil well has enough
downhole pressure to reach a suitable wellhead production pressure and maintain an
acceptable well-flow. If the formation pressure is too low, and water or gas injection
cannot maintain pressure or is not suitable, then the well must be artificially lifted.
For smaller wells, 0.7 MPa (100 PSI) wellhead pressure with a standing column of
liquid in the tubing is considered a rule-of-thumb to allow the well to flow. Larger
30

wells will be equipped with artificial lift to increase production even at much higher
pressures. Some artificial lift methods are:
3.6.1 Rod Pumps
Sucker Rod
Pumps, also
called Donkey
pumps or beam
pumps, are the
most common
artificial-lift
system used in
land-based
operations. A
motor drives a
reciprocating beam, connected to a polished rod passing into the tubing via a stuffing
box. The sucker rod continues down to the oil level and is connected to a plunger
with a valve.
On each upward stroke, the plunger lifts a volume of oil up and through the wellhead
discharge. On the downward stroke it sinks (it should sink, not be pushed) with oil
flowing though the valve. The motor speed and torque is controlled for efficiency
and minimal wear with a Pump off Controller (PoC). Use is limited to shallow
reservoirs down to a few hundred meters, and flows up to about 40 liters (10 gal) per
stroke.
3.6.2 Downhole Pumps
Downhole pump insert the
whole pumping mechanism
into the well. In modern
installations, an Electrical
Submerged Pump (ESP) is
inserted into the well. Here the
whole assembly consisting of a
long narrow motor and a multi
phase pump, such as a PCP
(progressive cavity pump) or
centrifugal pump, hangs by an
electrical cable with tension
members down the tubing. Ill:
Wikipedia.org
31

Installations down to 3.7 km with power up to 750 kW have been installed. At these
depths and power ratings, Medium Voltage drives (up to 5kV) must be used.
ESPs works in deep reservoirs, but lifetime is sensitive to contaminants such as sand,
and efficiency is sensitive to GOR (Gas Oil Ratio) where gas over 10% dramatically
lowers efficiency.
3.6.3 Gas Lift
Gas Lift injects gas into the
well flow. The downhole
reservoir pressure falls off to
the wellhead due to the
counter pressure from weight
of the oil column in the
tubing. Thus a 150 MPa
reservoir pressure at 1600
meters will fall to zero
wellhead pressure if the
specific gravity is 800 kg/m 2 .
(0,8 times water). By
injecting gas into this oil, the
specific gravity is lowered
and the well will start to
flow. Typically gas in
injected between casing and
tubing, and a release valve on
a gas lift mandrel is inserted
in the tubing above the
packer. The valve will open at a set pressure to inject lift gas into the tubing. Several
mandrels with valves set at different pressure ranges can be used to improve lifting
and start up. Ill: Schlumberger oilfield glossary
Gas lift can be controlled for a single well to optimize production, and to reduce
slugging effects where the gas droplets collect to form large bubbles that can upset
production.
Gas lift can also be optimized over several wells to use available gas in the most
efficient way.
32

3.6.4 Plunger Lift
Plunger lift is normally
used on low pressure gas
wells with some
condensate, oil or water,
or high gas ratio oil wells.
In this case the well flow
conditions can be so that
liquid starts to collect
downhole and eventually
blocks gas so that the well
production stops. In this
case a plunger with an
open/close valve can be
inserted in the tubing. A
plunger catcher at the top
opens the valve and can
hold the plunger, while
another mechanism
downhole will close the
valve.
The cycle starts with the
plunger falling into the
well with its valve open. Gas, condensate and oil can pass though the plunger until it
reaches bottom. There the valve is closed, now with a volume of oil, condensate or
water on top. Gas pressure starts to accumulate under the plunger and after some
time pushes the plunger upwards, with liquid on top, which eventually flows out of
the wellhead discharge.
When the plunger reaches the wellhead plunger catcher, the valve opens and allows
gas to flow freely for some time while new liquid collects at the bottom. After some
preset time the catcher will release the plunger, and the cycle repeats.
3.7 Well workover, intervention and stimulation.
After some time in operation, the well may become less productive or faulty due to
residue build up, sand erosion, corrosion or reservoir clogging.
Well workover is the process of performing major maintenance on an oil or gas
well. This might include replacement of the tubing, cleanup or new completions, new
33

perforation and various other maintenance works such as installation of gas lift
mandrels, new packing etc.
Through-tubing workover operations are work performed with special tools that do
not necessitate the time consuming full workover procedure including replacement
or removal of tubing. Well maintenance without killing the well and performing full
workover is time saving and is often called well intervention. Various operations
that are performed by lowering instruments or tools on a wire into the well are called
wireline operations.
Work on the reservoir such as chemical injection, acid treatment, heating etc is
referred to as reservoir stimulation. Stimulation serves to correct various forms of
formation damage and improve flow. Damage is a generic term for accumulation of
particles and fluids that block fractures and pores and limit reservoir permeability.
• Acids, such as HCL (Hydrochloric Acid) are used open up calcerous
reservoirs and to treat accumulation of calcium carbonates in the reservoir
structure around the well. Several hundred liters of acid (typically 15%
solution in water) are pumped into the well under pressure to increase
permeability of the formation. When the pressure is high enough to open
fractures, the process is called fracture acidizing. If the pressure is lower, it
is called matrix acidizing.
• Hydraulic fracturing is an operation in which a specially blended liquid is
pumped down a well and into a formation under pressure high enough to
cause the formation to crack open, forming passages through which oil can
flow into the well bore. Sand grains, aluminum pellets, walnut shells, glass
beads, or similar materials (propping agents) are carried in suspension by
the fluid into the fractures. When the pressure is released at the surface, the
fractures partially close on the proppants, leaving channels for oil to flow
through to the well. The fracture channels may be up to 100 meters, several
hundred feet long.
• Explosive fracturing, when explosives are used to fracture a formation. At
the moment of detonation, the explosion furnishes a source of high-pressure
gas to force fluid into the formation. The rubble prevents fracture healing,
making the use of proppants unnecessary.
• Damage removal refers to other forms of removing formation damage, such
as flushing out of drill fluids.
Flexible coiled tubing can be wound on a large diameter drum and can be inserted
and removed much quicker than tubing installed from rigid pipe segments. Well
workover equipment including coiled tubing is often mounted on well workover rigs.
34

3.8 Unconventional sources of oil and gas
The descriptions above are valid for conventional oil and gas sources. As demand
increases, prices soar and new conventional resources become harder to find,
production of oil and gas from unconventional sources become more attractive.
These unconventional sources include very heavy crudes, oil sands, oil shale, gas and
synthetic crude from coal, coal bed methane and biofuels. Estimates for conventional
proven producible oil and gas reserves vary somewhat. The current increase in
consumption is just under 2 % per year, or 15% - 20% in a decade for different
products, even with energy saving efforts. If this trend continues the time to go
figures quoted above will be reduced by one third.
The following table shows current estimates and consumption:
2006 Proven reserves
(average)
Barrels Oil
Equivalent (OE)
35
Daily OE
consumption
Time to go at
current
consumption
Crude Oil 1100 billion bl 1100 bill bl 76 mill bl 40 years
Natural gas 175 trillion scm 1150 bill bl 47 mill bl 67 years
Estimates on undiscovered conventional and unconventional sources vary widely as
the oil price; economical production cost and discovery are uncertain factors. With
continued high oil prices, figures around 1-2 trillion barrels conventional (more gas
than oil) and 3 trillion barrels unconventional are often quoted, for a total remaining
producible hydrocarbon reserve of about 5 trillion barrels oil equivalent. Within a
decade, it is expected that up to a third of oil fuel production may come from
unconventional sources.
3.8.1 Extra Heavy Crude
Very Heavy crude are hydrocarbons with an API grade of about 15 or below. The
most extreme heavy crude currently extracted are Venezuelan 8 API crude e.g. in
eastern Venezuela (Orinoco basin). If the reservoir temperature is high enough, the
crude will flow from the reservoir. In other areas, such as Canada, the reservoir
temperature is lower, and steam injection must be used to stimulate flow form the
formation.
When reaching the surface, the crude must be mixed with a diluent (often LPGs) to
allow it to flow in pipelines. The crude must be upgraded in a processing plant to
make lighter SynCrude with a higher yield of high value fuels. Typical SynCrude
have an API of 26-30. The diluent is recycled by separating it out and piped back to
the wellhead site. The crude undergoes several stages of hydrocracking and coking to
form lighter hydrocarbons and remove coke. It is often rich in sulfur (sour crude)
which must be removed.

3.8.2 Tar sands
Tar sands can be often strip mined. Typically two tons of tar sand will yield one
barrel of oil. A typical tar sand contains sand grains with a water envelope, covered
by a bitumen film that may contain 70% oil. Various fine particles can be suspended
in the water and bitumen.
This type of tar sand can be processed with
water extraction. Hot water is added to the
sand, and the resulting slurry is piped to the
extraction plant where it is agitated and the oil
skimmed from the top. Provided that the water
chemistry is appropriate (adjusted with
chemical additives), it allows bitumen to
separate from sand and clay. The combination
of hot water and agitation releases bitumen
from the oil sand, and allows small air bubbles
to attach to the bitumen droplets. The bitumen
froth floats to the top of separation vessels,
and is further treated to remove residual water
and fine solids. It can then be transported and processed the same way as for extra
heavy crude.
It is estimated that around 80% of the tar sands are too far below the surface for the
current open-pit mining technique. Techniques are being developed to extract the oil
below the surface. These techniques requires a massive injection of steam into a
deposit, thus liberating the bitumen underground, and channeling it to extraction
points where it would be liquefied before reaching the surface. The tar sands of
Canada (Alberta) and Venezuela are estimated at 250 billion barrels, equivalent to
the total reserves of Saudi Arabia
3.8.3 Oil Shale
Most oil shales are fine-grained sedimentary rocks containing relatively large
amounts of organic matter from which significant amounts of shale oil and
combustible gas can be extracted by destructive distillation. One of the largest
known locations is the oil shale locked in the 40.000 km 2 (16000 sq-mile) Green
River Formation in Colorado, Utah, and Wyoming.
36

Oil shale differs from coal whereby the organic matter in shales has a higher atomic
Hydrogen to Carbon ratio. Coal also has an organic to inorganic matter ratio of more
than 4,75 to 5 while as oil shales have a higher content of sedimentary rock. Sources
estimate the world reserves of Oil Shales at more than 2,5 trillion barrels.
Oil shales are thought to form when algae and sediment deposit in lakes, lagoons and
swamps where an anaerobic (oxygen free) environment prevent the breakdown of
organic matter, thus allowing it to accumulate in thick layers. Thet is later covered
with overlying rock to be baked under high temperature and pressure. However heat
and pressure was lower than in oil and gas reservoirs. The shale can be strip mined
and processed with distillation. Extraction with fracturing and heating is still
relatively unproven. Companies are experimenting with direct electrical heating
rather than e.g. steam injection. Extraction cost is currently around 25-30 USD per
barrel.
3.8.4 Coal, Coal Gasification and Liquefaction
Coal is similar in origin to oil shales but typically formed from anaerobic decay of
peat swamps relatively free from nonorganic sediment deposits, reformed by heat
and pressure. To form a 1 meter thick coal layer, as much as 30 meters of peat was
originally required. Coal can vary from relatively pure carbon to carbon soaked with
hydrocarbons, sulfur etc.
It has been clear for decades that synthetic oil could be created from coal. Coal
gasification will transform coal into e.g. methane. Liquefaction such as the Fischer-
Tropsch process will turn methane into liquid hydrocarbons. (Typically on the form
C n H 2n+2 )
In addition, coal deposits contain large amounts of methane, referred to as coal bed
methane. It is more difficult to produce than normal natural gas (which is also
largely methane), but could add as much as 5-10% to natural gas proven reserves.
3.8.5 Methane Hydrates
Methane hydrates are the most recent form of
unconventional natural gas to be discovered and
researched. These formations are made up of a
lattice of frozen water, which forms a sort of cage
around molecules of methane. Hydrates were first
discovered in permafrost regions of the Arctic and
have been reported from most deepwater
continental shelves tested. The methane can
37

origiate from organic decay. At the sea bottom, under high pressure and low
temperatures, the hydrate is heavier than water and will not escape, but stay at the
bottom. Research has revealed that they may be much more plentiful than first
expected. Estimates range anywhere from 180 to over 5800 trillion scm. The US
Geological Survey estimates that methane hydrates may contain more organic carbon
than the world's coal, oil, and conventional natural gas – combined. However,
research into methane hydrates is still in its infancy.
3.8.6 Biofuels
Biofuels are produced from specially grown products such as oil seeds or sugars, and
organic waste e.g. from the forest industry.
Alcohol is distilled from fermented sugars and/or starch (e.g. wood or grain) to
produce Ethanol that can be burnt alone, or mixed with ordinary petrol.
Biodiesel is made through a chemical process called transesterification whereby the
glycerin is separated from fat or vegetable oil. The process leaves behind two
products -- methyl esters (the chemical name for biodiesel) and glycerin (a valuable
byproduct usually sold to be used in soaps and other products). Biodiesel contains no
petroleum, but it can be blended at any level with petroleum diesel to create a
biodiesel blend. It can be used in compression-ignition (diesel) engines with little or
no modifications. Biodiesel is simple to use, biodegradable, nontoxic, and essentially
free of sulfur and aromatics.
Brazil and Sweden are two countries with full scale biofuel programs.
3.8.7 Hydrogen
Although not a hydrocarbon ressource, hydrogen can be used in place of or
complement traditional hydrocarbon based fuels. Hydrogen is clean burning, which
means that when hydrogen reacts with oxygen, either in a conventional engine or a
fuel cell, water vapor is the only emission. (Combustion with air at high temperatures
will also form nitrous oxides).
Hydrogen can be produced either from hydrocarbons (natural gas, ethanol etc.) or by
electrolysis. Production from natural gas (catalytic: CH 4 + ½ O 2 2H 2 + CO, CO +
½ O 2 CO 2 ) also produces energy and carbondioxide, but has the advantage over
methane gas that carbon dioxide can be removed and handled at a central location
rather than from each consumer (car, ship etc.), providing a cleaner energy source.
Hydrogen is also produced with electrolysis from water, or in various recycling
processes in the chemical industry. (e.g. Hydrocloric acid recycle in the polyurethane
38

process). The energy requirement can then come from a renewable source such as
hydroelectric, solar, wind, wave, or tidal, where hydrogen acts as an energy
transport medium replacing bulky batteries, to form a full clean, renewable energy
source supply chain.
In both cases the main problem is overall economy, distribution and storage from the
fact that hydrogen cannot easily be compressed to small volumes, but requires quite
bulky gas tanks for storage.
39

4 The Oil and Gas Process
The oil and gas process is the process equipment that takes the product from the
wellhead manifolds and delivers stabilized marketable products, in the form of Crude
Oil, Condensate or Gas. Components of the process also exist to test products and
clean waste products such as produced water.
Our example process, for
the Norsk Hydro Njord
floater is shown on the
next page. This is a
medium size platform
with one production train
and a production of 40-
45.000 barrels per day
(bpd). This is actual
production, after
separation of water and
gas. The associated gas
and is used for on board
power generation and gas
reinjection. There is only
one separation and gas compression train. The water is treated and released (it could
also have been reinjected). This process is quite representative for hundreds of
similar size installations, and only more complete gas treatment and gas export is
missing to form a complete gas production facility, Njord sends the oil via a short
pipeline to a nearby storage floater. On gravity base platforms, FPSO (Floating
Production and Storage Operations) and onshore plants this storage will be a part of
the main installation if the oil is not piped out directly. Photo: Norsk Hydro ASA
A large number of connections to chemicals, flare etc are shown, these systems are
described separately.
Nård main process illustration: Norsk Hydro ASA
40

4.1 Manifolds and Gathering
4.1.1 Pipelines, and Risers
This facility uses Subsea production wells. The typical High Pressure (HP) wellhead
at the bottom right, with its Christmas tree and choke, is located on the sea bottom. A
production riser (offshore) or gathering line (onshore) brings the well flow into the
manifolds. As the reservoir is produced, wells may fall in pressure and become Low
Pressure (LP) wells.
This line may include several check valves. The choke, master and wing valves are
relatively slow, therefore in case of production shutdown, pressure before the first
closed sectioning valve will rise to the maximum wellhead pressure before these
valves can close. The pipelines and risers are designed with this in mind.
Short pipeline distances is not a problem, but longer distances may cause multiphase
well flow to separate and form severe slugs, plugs of liquid with gas in between,
traveling in the pipeline. Severe slugging may upset the separation process, and also
cause overpressure safety shutdowns. Slugging might also occur in the well as
described earlier. Slugging may be controlled manually by adjusting the choke, or
with automatic slug controls. Further, areas of heavy condensate might form in the
pipelines. At high pressure, these plugs may freeze at normal sea temperature, e.g. if
production is shut down or with long offsets. This may be prevented by injecting
ethylene glycol. Glocol injection is not used on Njord.
The Njord floater has topside chokes for Subsea wells. The diagram also shows that
Kill Fluid, essentially high specific gravity Mud, can be injected into the well before
the choke.
4.1.2 Production, test and injection manifolds
Check valves allow each well to be routed into one or more of several Manifold
Lines. There will be at least one for each process train plus additional Manifolds for
test and balancing purposes. In the diagram we show three: Test, Low Pressure and
High Pressure Manifolds. The test manifold allows one or more wells to be routed to
the test separator. Since there is only one process train, the HP and LP manifolds
allow groups of HP and LP wells to be taken to the first and second stage separators
respectively. The chokes are set to reduce the wellhead flow and pressure to the
desired HP and LP pressures respectively.
The desired setting for each well and which wells produce at HP and LP for various
production levels are defined by reservoir specialists to ensure the optimum
production and recovery rate.
42

4.2 Separation
As described earlier, the well-stream may consist of Crude oil, Gas, Condensates,
water and various contaminants. The purpose of the separators is to split the flow
into desirable fractions.
4.2.1 Test Separators and Well test
Test separators are used to separate the well flow from one or more wells for analysis
and detailed flow measurement. In this way, the behavior of each well under
different pressure flow conditions can be determined. This normally takes place
when the well is taken into production and later at regular intervals, typically 1-2
months and will measure the total and component flow rates under different
production conditions. Also undesirable behavior such as slugging or sand can be
determined. The separated components are also analyzed in the laboratory to
determine hydrocarbon composition of the Gas oil and Condensate.
The test separator can also be used to produce fuel gas for power generation when
the main process is not running. In place of a test separator one could also use a three
phase flow meter to save weight.
4.2.2 Production separators
The main separators are gravity type. On the right you see the main components
around the first stage separator.
As mentioned the production
choke reduces will pressure to
the HP manifold and First
stage separator to about 3-5
MPa (30-50 times atmospheric
pressure). Inlet temperature is
often in the range of 100-150
degrees C. On the example
platform, the well stream is
colder due to Subsea wells and
risers.
The pressure is often reduced
in several stages; here three
stages are used, to allow
controlled separation of
volatile components. The
purpose is to achieve
43

maximum liquid recovery and stabilized oil and gas, and separate water. A large
pressure reduction in a single separator will cause flash vaporization leading to
instabilities and safety hazards.
The retention period is
typically 5 minutes,
allowing the gas to bubble
out, water to settle at the
bottom and oil to be taken
out in the middle. In this
platform the water cut
(percentage water in the
well flow) is almost 40%
which quite high. In the
first stage separator, the
water content is typically
reduced to less than 5%.
At the crude entrance there is a baffle slug catcher that will reduce the effect of
slugs (Large gas bubbles or liquid plugs). However some turbulence is desirable as
this will release gas bubbles faster than a laminar flow.
At the end there are barriers up to a certain level to keep back the separated oil and
water. The main control loops are the oil level control loop (EV0101 20 above)
controlling the oil flow out of the separator on the right, and the gas pressure loop at
the top.(FV0105 20 above) These loops are operated by the Control System. An
important function is also to prevent gas blow-by which happens when low level
causes gas to exit via the oil output causing high pressure downstream. There are
generally many more instruments and control devices mounted on the separator.
These will be discussed later.
The liquid outlets from the separator will be equipped with vortex breakers to
reduce disturbance on the liquid table inside. This is basically a flange trap to break
any vortex formation and ensure that only separated liquid is tapped off and not
mixed with oil or water drawn in though these vortices. Similarly the gas outlets are
equipped with demisters, essentially filters that will remove liquid droplets in the
gas.
Emergency Valves (EV) are sectioning valves that will separate the process
components and blow-down valves that will allow excess hydrocarbons to be burned
off in the flare. These valves are operated if critical operating conditions are detected
or on manual command, by a dedicated Emergency Shutdown System. This might
44

involve partial shutdown and shutdown sequences since the flare might not be able to
handle a full blow-down of all process sections simultaneously.
A 45.000 bpd design production with gas and 40% water cut this gives about 10
cubic meters from the wellheads per minute. There also needs to be enough capacity
to handle normal slugging from wells and risers. This means the separator has to be
about 100 cubic meters, e.g. a cylinder 3 m in diameter and 14 meters long. At the
rated operating pressure this means a very heavy piece of equipment, typically
around 50 tons for this size. This limits the practical number of stages. Other types of
separators such as vertical separators, cyclones (centrifugal separation) can be use to
save weight, space or improve separation (see later) There also has to be a certain
minimum pressure difference between each stage to allow satisfactory performance
in the pressure and level control loops.
Chemical additives are discussed later.
4.2.3 Second stage separator
The second stage separator is quite similar to the first stage HP separator. In addition
to output from the first stage, it will also receive production from wells connected to
the Low Pressure manifold. The pressure is now around 1 MPa (10 atmospheres) and
temperature below 100 degrees C. The water content will be reduced to below 2%.
An oil heater could be located between the first and second stage separator to reheat
the oil/water/gas mixture. This will make it easier to separate out water when initial
water cut is high and temperature is low. The heat exchanger is normally a tube/shell
type where oil passes though tubes in a cooling medium placed inside an outer shell.
4.2.4 Third stage separator
The final separator here is a two phase
separator, also called a flash-drum. The
pressure is now reduced to about
atmospheric pressure (100 kPa) so that
the last heavy gas components will boil
out. In some processes where the initial
temperature is low, it might be
necessary to heat the liquid (in a heat
exchanger) again before the flash drum
to achieve good separation of the heavy
components. There are level and
pressure control loops.
45

As an alternative, when the production is mainly gas, and remaining liquid droplets
have to be separated out, the two phase separator can be a Knock-Out Drum (K.O.
Drum).
4.2.5 Coalescer
After the third stage separator, the oil
can go to a coalescer for final removal
of water. In this unit the water content
can be reduced to below 0.1%. The
coalescer is completely filled with
liquid: water at the bottom and oil on
top. Inside electrodes form an electric
field to break surface bonds between
conductive water and isolating oil in an
oil water emulsion. The coalescer field plates are generally steel, sometimes covered
with dielectric material to prevent short circuits. The critical field strength in oil is in
the range 0.2 to 2 kV/cm. Field intensity and frequency as well as the coalescer grid
layout is different for different manufacturers and oil types.
4.2.6 Electrostatic Desalter
If the separated oil
contains unacceptable
amounts of salts, it can be
removed in an
electrostatic desalter (Not
used in the Njord
example) The salts, which
may be Sodium, Calcium
or Magnesium chlorides
comes from the reservoir water and is also dissolved in the oil. The desalters will be
placed after the first or second stage separator depending on Gas Oil Ratio (GOR)
and Water cut. Photo: Burgess Manning Europe PLC
4.2.7 Water treatment
On an installation such as this, when the water cut is high, there will be a huge
amount of produced water. In our example, a water cut of 40% gives a water
production of about 4000 cubic meters per day (4 million liters) that must be cleaned
46

efore discharge to sea. Often this water contains sand particles bound to the
oil/water emulsion.
The environmental regulations in most countries are quite strict, as an example, in
the North-East Atlantic the OSPAR convention limits oil in water discharged to sea
to 40 mg/liter (ppm).
It also places limits other forms of contaminants. This still means up to one barrel of
oil per day for the above production, but in this form, the microscopic oil drops are
broken down fast by natural bacteria.
Various equipment is used; the illustration shows a typical water treatment system.
Water from the separators and coalescers first goes to a sand cyclone, which
removes most of the sand. The sand is further washed before it is discharged.
The water then goes to a hydrocyclone, a centrifugal separator that will remove oil
drops. The hydrocyclone creates a standing vortex where oil collects in the middle
and water is forced to the side.
Finally the water is collected in the water de-gassing drum. Dispersed gas will
slowly rise to the surface and pull remaining oil droplets to the surface by flotation.
The surface oil film is drained, and the produced water can be discharged to sea.
Recovered oil in the water treatment system is typically recycled to the third stage
separator.
47

4.3 Gas treatment and Compression
The gas train consist
of several stages, each
taking gas from a
suitable pressure level
in the production
separator’s gas outlet,
and from the previous
stage.
A typical stage is
shown to the right.
Incoming gas (on the
right) is first cooled in
a heat exchanger. It
then passes through
the scrubber to
remove liquids and goes into the compressor. The anti surge loop (thin orange line)
and the surge valve (UV0121 23) allows the gas to recirculate. The components are
described below.
4.3.1 Heat exchangers
For the compressor operate in an efficient way, the temperature of the gas should be
low. The lower the temperature is the less energy will be used to compress the gas
for a given final pressure and temperature. However both gas from separators and
compressed gas are relatively hot. When gas is compressed, it must remain in
thermodynamic balance, which means that the gas pressure times volume over
temperature (PV/T ) must remain constant. (PV = nkT). This ends up as a
temperature increase.
Temperature exchangers of
various forms are used to
cool the gas. Plate heat
exchangers (upper picture)
consist of a number of plates
where the gas and cooling
medium pass between
alternating plates in
opposing directions. Tube
and shell exchangers (next
48

picture) place tubes inside a
shell filled with of cooling
fluid. The cooling fluid is often
pure water with corrosion
inhibitors.
When designing the process it
is important to plan the thermal
energy balance. Heat should be
conserved e.g. by using the
cooling fluid from the gas train
to reheat oil in the oil train.
Excess heat is disposed e.g. by
sea water cooling. However
hot seawater is extremely
corrosive, so materials with
high resistance to corrosion, such as titanium must be used. Photo: SEC Shell and Tube
Heat Exchanges
4.3.2 Scrubbers and reboilers
The separated gas may contain mist and other liquid droplets. Liquid drops of water
and hydrocarbons also form when the gas is cooled in the heat exchanger, and must
be removed before it reaches the compressor. If liquid droplets enter the compressor
they will erode the fast rotating blades. A scrubber is designed to remove small
fractions of liquid from the gas.
49

Various gas drying equipment is available, but the most common suction
(compressor) scrubber is based on dehydration by absorption in Tri Ethylene Glycol
(TEG). The scrubber consists of many levels of glycol layers. A large number of gas
traps (enlarged detail) force the gas to bubble through each glycol layer as it flows
from the bottom up each division to the top.
Lean glycol is pumped in at the top, from the holding tank. It flows from level to
level against the gas flow as it spills over the edge of each trap. During this process it
absorbs liquids from the gas and comes out as rich glycol at the bottom. The holding
tank also functions as a heat exchanger for liquid from and to the reboilers.
The glycol is recycled by removing the absorbed liquid. This is done in the reboiler,
which is filled with rich glycol and heated to boil out the liquids at temperature of
about 130-180 °C (260-350°F) for a number of hours. Usually there is a distillation
column on the gas vent to further improve separation of glycol and other
hydrocarbons. For higher capacity there are often two reboilers which alternate
between heating rich glycol and draining recycled lean glycol.
On a stand alone unit the heat is supplied from a burner that uses the recovered
vaporized hydrocarbons. In other designs the heating will use a combination of hot
cooling media from other parts of the process and electric heaters, and recycle the
hydrocarbon liquids to the third stage separator.
4.3.3 Compressor anti surge and performance
Several types of compressors are used for gas compression, each with different
characteristics such as operating power, speed, pressure and volume:
• Reciprocating
Compressor that
use a piston and
cylinder design
with 2-2 cylinders
are built up to about
30 MW power,
around 500-1800
rpm (lower for
higher power) with
pressure up to
5MPa (500 bars). Used for lower capacity gas compression and high
reservoir pressure gas injection. Photo: Ariel corp.
50

• Screw compressors are
manufactured up to
several MW, synchronous
speed (3000/3600 rpm)
and pressure up to about
2.5 MPa (25 bar). Two
counter rotating screws
with matching profiles
provide positive
displacement and a wide
operating range. Typical
use is natural gas
gathering.
Photo: Mycom/Mayekawa mfg.
• Axial blade and fin type
compressors with up to 15
wheels provide high
volumes at relatively low
pressure differential
(discharge pressure 3-5
times inlet pressure),
speeds of 5000-8000 rpm,
and inlet flows to 200.000
m3/hour. Applications
include air compressors
and cooling compression
in LNG plants. Axial rotor
photo: Dresser Rand
• The larger oil and gas
installations use
Centrifugal compressors
with 3-10 radial wheels,
6000 – 20000rpm (highest
for small size), up to 80
MW load at discharge
pressure of up to 50bars
and inlet volumes of up to
500.000 m3/hour. Pressure
differential up to 10.
Photo: Dresser Rand
51

Most compressors will not cover the full pressure range efficiently. The lowest
pressure is atmospheric, for gas to pipeline, some 3 to 5 MPa (30-50 bar) pressure is
used, while reservoir reinjection of gas will typically require 20 MPa (200 bars) and
upwards since there is no liquid in the tubing and the full reservoir pressure must be
overcome. Therefore compression is divided into several stages to improve
maintenance and availability. Also due to single unit power limitations compression
is often divided in several parallel trains. This is not the case in the example since
gas is not exported, and reinjection can be interrupted during maintenance periods.
Compressors are driven by gas turbines or electrical motors (for lower power also
reciprocating engines, steam turbines are sometimes used if thermal energy is
available). Often several stages in the same train are driven by the same motor or
turbine.
The main operating parameters for a compressor is the flow and pressure differential.
The product defines the total loading, so there is a ceiling set by the maximum
design power. Further, there is a maximum differential pressure (Max P d ) and choke
flow (Max Q), the maximum flow that can be achieved. At lower flow, there is a
minimum pressure differential and flow before the compressor will “surge”: there is
not enough gas to operate. If variations in flow are expected or difference between
common shaft compressors will occur, the situation will be handled with
recirculation: A high flow, high pressure differential surge control valve will open to
let gas from the discharge side back into the suction side. Since this gas is heated it
will also pass through the heat exchanger and scrubber not to become overheated by
circulation.
52

The operating characteristics are defined by the manufacturer. In the above diagram
the blue lines mark constant speed lines. The maximum operating limits are set by
the orange line as described above. The surge domain is the area to the left of the red
surge curve.
The object of the compressor performance control is to keep the operating point
close to the optimal setpoint without violating the constraints, by means of control
outputs, such as the speed setting. However gas turbine speed control response is
relatively slow and even electrical motors are not fast enough since the surge
response must be in the 100 mS range. The anti surge control will protect the
compressor from going into surge by operating the surge control valve. The basic
strategy is to use distance between operating point and surge line to control the valve
with a slower response time starting at the surge control line. Crossing the surge trip
line will control a fast response opening of the surge valve to protect the compressor.
Operation with recirculation wastes energy (which could result in unnecessary
emissions) and wear, particularly of the surge valve. Each vendor supplies several
variants of compressor control and anti surge control to optimize performance, based
on various corrective and predictive algorithms. Some strategies include:
• Setpoint adjustment: If rapid variations in load cause surge valve action, the
setpoint will be moved to increase the surge margin.
• Equal margin: The setpoint is adjusted to allow equal margin to surge
between several compressors.
• Model based control: Outside the compressor itself, the main parameter for
the surge margin is the total volume from the surge valve to the compressor
suction inlet, and the response time for the surge valve flow. A model
predictive controller could predict surge conditions and react faster to real
situations while preventing unnecessary recirculation.
Since compressors are relatively maintenance intensive and potentially expensive to
replace, several other systems are normally included:
Load management:
To balance loading among several compressors in a train
and between trains, the compressor control system often
includes algorithms for load sharing, load shedding and
loading. Compressors are normally purged with inert gas,
such as Nitrogen, during longer shutdowns, e.g. for
maintenance. Therefore, startup and shutdown sequences
will normally include procedures to introduce and remove
the purge gas.
53

Vibration:
Speed governor
Vibration is a good indicator of problems in compressors,
and accelerometers are mounted on various parts of the
equipment to be logged and analyzed by a vibration
monitoring system.
If the compressor is turbine driven, a dedicated speed
governor handles the fuel valves and other controls on the
turbine to maintain efficiency and control rotational speed.
For electrical motors this function is handled by a variable
speed drive.
The final function around the compressor itself is lube and seal oil handling. Most
compressors have wet seals, which are traps around axles where oil at high pressure
prevents gas from leaking out to atmosphere or other parts of the equipment. Oil is
used for lubrication of the high speed bearings. This oil gradually absorbs gas under
pressure and may be come contaminated. So it needs to be filtered and degassed.
This happens in smaller reboilers much the same way as for the glycol reboilers
described earlier.
4.3.4 Gas Treatment
When the gas is exported, many gas trains include additional equipment for further
gas processing, to remove unwanted components such as hydrogen sulfide and
carbon dioxide. These gases are called acids and sweetening /acid removal is the
process of taking them out.
Natural gas sweetening methods include absorption processes, cryogenic processes;
adsorption processes (PSA, TSA and iron sponge) and membranes. Often hybrid
combinations are used, such as cryogenic and membranes.
Gas treatment could also include calibration. If the delivery specification is for a
specific calorific value (BTU per scf or MJ per scm) gas with higher values can be
adjusted by adding an inert gas, such as nitrogen. This is often done at a common
point such as a pipeline gathering system or a pipeline onshore terminal.
4.4 Oil and Gas Storage, Metering and Export
The final stage before the oil and gas leaves the platform consists of storage, pumps
and pipeline terminal equipment.
4.4.1 Fiscal Metering
Partners, authorities and customers all calculate invoices, taxes and payments based
on the actual product shipped out. Often custody transfer also takes place at this
54

point, means a transfer of responsibility or title from the producer to a customer,
shuttle tanker operator or pipeline operator.
Fig. 1 Metering System
¨
Although some small installations are still operated with dipstick and manual
records, larger installations have analysis and metering equipment. To make sure
readings are accurate, a fixed or movable prover loop for calibration is also installed.
The figure shows a full liquid hydrocarbon (oil and condensate) metering system.
The analyzer instruments on the left provides product data such as density, viscosity
and water content. Pressure and temperature compensation is also included.
For liquid, turbine meters with dual pulse outputs are most common. Alternatives are
positive displacement meters (passes a fixed volume per rotation or stroke) and
coriolis massflow meters. These instruments can not cover the full range with
sufficient accuracy. Therefore the metering is split into several runs, and the number
of runs in use depends on the flow. Each run employs one meter and several
instruments to provide temperature and pressure correction. Open/Close valves allow
runs to be selected and control valves can balance the flow between runs. The
instruments and actuators are monitored and controlled by a flow computer. If the
55

interface is not digital, dual pulse trains are used to allow direction sensing and fault
finding.
To obtain required accuracy, the meters are calibrated. The most common method is
a prover loop. A prover ball moves though the loop, and a calibrated volume is
provided between the two detectors (Z). When a meter is to be calibrated the four
way valve opens to allow oil to flow behind the ball. The number of pulses from it
passes one detector Z to the other is counted. After one loop the four way valve turns
to reverse flow direction and the ball moves back providing the same volume and in
reverse, again counting the pulses. From the known reference volume, number of
pulses, pressure and temperature the flow computer can calculate the meter factor
and provide accurate flow measurements using formulas form industry standard
organizations such as API MPMS and ISO 5024. The accuracy is typically ± 0.3% of
standard volume.
Gas metering is similar, but instead,
analyzers will measure hydrocarbon
content and energy value (MJ/scm or
BTU, Kcal/scf) as well as pressure and
temperature. The meters are normally
orifice meters or ultrasonic meters. Orifice
plates with a diameter less than the pipe
are mounted in cassettes. The pressure
differential over the orifice plate as well
as pressure and temperature is used in
standard formulas (such as AGA 3 and
ISO 5024/5167) to calculate normalized
flow. Different ranges are accommodated
with different size restrictions. Orifice plates are sensitive to build up of residue and
wear on the edges of the hole. Larger new installations therefore prefer ultrasonic gas
meters that work by sending
multiple ultrasonic beams
across the path and measure
the Doppler Effect.
Gas metering is less accurate
than liquid, typically ±1.0% of
mass. There is usually not a
prover loop, instead the
instruments and orifice plates
are calibrated in separate
equipment.
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LNG is often metered with massflow meters that can operate at the required low
temperature. A three run LNG metering skid is shown above.
At various points in the movement of oil and gas, similar measurements are taken,
usually in a more simplified variant. Examples are Flare gas, Fuel Gas and Injected
gas where required accuracy is 2-5% percent.
4.4.2 Storage
On most production sites, the oil and gas is piped directly to a refinery or tanker
terminal. Gas is difficult to store locally, but occasionally underground mines,
caverns or salt deposits can be used to store gas.
On platforms without pipeline,
oil is stored in onboard storage
tanks to be transported by
shuttle tanker. The oil is stored
in storage cells around the
shafts on concrete platforms,
and in tanks on floating
platforms. On some floaters, a
separate storage tanker is used.
In both cases ballast handling
is important to balance the
buoyancy when the oil volume varies. For onshore fixed roof tanks are used for
crude, floating roof for condensate. Also rock caverns are used.
Special tank gauging systems such as Level radars, Pressure or Float are used to
measure the level in storage tanks, cells and caverns. The level measurement is
converted to volume via tank strapping tables (dependent on tank geometry) and
compensated for temperature to provide standard volume. Float gauges can also
calculate density, and so mass can be provided.
A tankfarm consists of 10-100 tanks of varying volume for a total capacity typically
in the area of 1 - 50 million barrels. Storage for shuttle tankers normally store up to
two weeks of production, one week for normal cycle and one extra week for delays
e.g. bad weather. This could amount to several million barrels.
Accurate records of volumes and history is kept to document what is received and
dispatched. For installations that serve multiple production sites, different qualities
and product blending must also be handled. Another planning task is forecasting for
future received and delivered product to make sure that the required amount of sold
product is available and that sufficient capacity is reserved for future received
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products. A tankfarm management system keeps track of these parameters and
constraints, logs the operations taking place and overall consolidation of operations.
4.4.3 Marine Loading
Loading systems consist
of one or more loading
arms / jetties, pumps,
valves and a metering
system.
Tanker loading systems
are complex, both
because of the volume
involved, and because
several loading arms
will normally interact
with the tanker's ballast
system to control the
loading operation. The
tanks must be filled in a certain sequence; otherwise the tanker's structure might be
damaged due to uneven stresses. It is the responsibility of the tanker's ballast system
to signal data to the loading system and to operate the different valves and monitor
the tanks on board the ship.
4.4.4 Pipeline terminal
The gas pipeline is fed from the High Pressure compressors. Oil pipelines are driven
by separate booster pumps. For longer pipelines, intermediate compressor stations or
pump stations will be required due to distance or crossing of mountain ranges.
The pipeline terminal includes termination systems for the pipeline. At least a pig
launcher and receiver will be included, to allow insertion of a pipeline pigging
device that is used to clean or inspect the pipeline on the inside. This is essentially a
large chamber that can be pressurized and purged to insert and remove the pig or
scraper without depressurizing the pipeline. The pig is often driven by pipeline flow.
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5 Utility systems
This chapter contains an overview of the various systems that provides utilities or
support the main process.
5.1 Control and Safety Systems
5.1.1 Process Control
A process control system is used to monitor data and control equipment on the plant.
Very small installations may use hydraulic or pneumatic control systems, but larger
plants with up to 30.000 signals to and from the process require a dedicated
distributed control system. The purpose of this system is to read values from a large
number of sensors, run programs to monitor the process and control valves switches
etc. to control the process. At the same time values, alarms, reports and other
information are presented to the operator and command inputs accepted.
Process control systems consist of the following components:
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• Field instrumentation: sensors and switches that sense process conditions
such as temperature, pressure or flow. These are connected over single and
multiple pair electrical cables (hardwired) or communication bus systems
called fieldbus.
• Control devices, such as Actuators for valves, electrical switchgear and
drives or indicators are also hardwired or connected over fieldbus.
• Controllers execute the control algorithms so that desired actions are taken.
The controllers will also generate events and alarms based on changes of
state and alarm conditions and prepare data for operators and information
systems.
• A number of servers perform the data processing required for data
presentation, historical archiving, alarm processing and engineering
changes.
• Clients such as operator stations and engineering stations are provided for
human interfaces.
• The communication can be laid out in many different configurations, often
including connections to remote facilities, remote operations support and
similar.
The main function of the control system is to make sure the production, processing
and utility systems operate efficiently within design constraints and alarm limits.
The control is typically specified in programs s a combination of logic and control
function blocks such as AND, ADD, PID. For a particular system, a library of
standard solutions such as Level Control Loop, Motor Control is defined. This means
that the system can be specified with combinations of typical loops, consisting of one
or more input devices, function blocks and output devices, rather than formal
programming.
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The system is operated from
the Central Control Room
(CCR) with a combination
of graphical process
displays, alarm lists, reports
and historical data curves.
Desk screens are often used
in combination with large
wall screens as shown on the
right. With modern system
the same information is
available to remote locations such as an onshore corporate operations support centre.
Field devices in most process areas must be protected not to
act as ignition sources for potential hydrocarbon leaks.
Equipment is explosive hazard classified e.g. as safe by
pressurization (Ex.p), safe by explosive proof encapsulation
(Ex.d) or intrinsically safe (Ex.i). All areas are mapped into
explosive hazard zones from Zone 0 (Inside vessels and
pipes), Zone 1 (Risk of hydrocarbons), Zone 2 (Low risk of
hydrocarbons) and Safe Area.
Beyond the basic functionality the control system can be used for more advanced
control and optimization functions. Some examples are:
• Well control may include automatic startup and shutdown of a well and/or a
set of wells. Applications can include optimization and stabilization of
artificial lift such as Pump off control and Gas lift Optimization.
• Flow assurance serves to make sure that the flow from wells, in pipelines
and risers are stable and maximized under varying pressure, flow and
temperatures. Unstable flow can result in slug formation, hydrates etc.
• Optimization of various processes to increase capacity or reduce energy
costs.
• Pipeline Management modeling, leak detection and pig tracking
• Support for Remote Operations, where facility data is available to company
specialists located at a central support center.
• Support for remote operation where the entire facility is unmanned or
without local operators full or part time, and is operated from a remote
location.
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5.1.2 Emergency Shutdown and Process Shutdown
The process control system
should control the process
when it is operating within
normal constrains such as
level, pressure and
temperature. The Emergency
Shutdown (ESD) and Process
Shutdown (PSD) systems will
take action when the process
goes into a malfunction or
dangerous state. For this
purpose the system maintains
four sets of limits for a process
value, LowLow (LL), Low (L),
High (H) and HighHigh (HH).
L and H are process warning
limits which alert to process
disturbances. LL and HH are
alarm conditions and detects
that the process is operating out of range and there is a chance of undesirable events
and malfunction.
Separate transmitters are provided for safety systems. One example is the LTLL
(Level Transmitter LowLow) or LSLL (Level Switch Low Low) alarm on the oil
level. When this condition is triggered, there is a risk of Blow-by which means gas
leaks out of the oil output
and gives high pressure in
the next separation stage or
other following process
equipment such as a desalter.
Transmitters are preferred
over switches because of
better diagnostics.
Emergency shutdown
actions are defined in a
cause and affect chart based
on a study of the process.
This HAZOP study
identifies possible
malfunctions and how they
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should be handled. On the left of the chart we have possible emergency events; on
top we find possible shutdown actions. On an oil and gas facility the primary
response is to isolate and depressurize In this case the typical action would be to
close the inlet and outlet Sectioning valves (EV 0153 20, EV 0108 20 and EV 0102
20 in the diagram), and open the blowdown valve (EV 0114 20). This will isolate the
malfunctioning unit and reduce pressure by flaring of the gas.
These actions are handled by the Emergency Shutdown System and Process
Shutdown System.
System requirements are set by official laws and regulations and industry standards
such as IEC 61508/61511. which set certification requirements for process safety
systems and set criteria for the safety integrity level (SIL) of each loop.
Events are classified on a scale, e.-g. 1 to 5 plus and Abandon Platform level. On this
scale, the lowest level, APS menas a complete shutdown and evacuation of the
facility. The next levels (ESD1, ESD2) define emergency complete shutdown. The
upper levels (i.e. PSD 3, PSD 4, PSD 5), represent single equipment or process
section shutdowns. A split between APS/ESD and PSD is done in large installations
because most signals are PSD and could be handled with less strict requirements.
The main requirements concern availability and diagnostics both on the system itself
and connected equipment. The prime requirement is on demand failure, or the
system’s ability to react with a minimum probability, to an undesirable event with a
certain time with. The second criteria is not to cause actions due to a spurious event
or malfunction.
Smaller ESD systems, e.g on wellhead platforms can be hydraulic or nonprogrammable..
5.1.3 Control and Safety configuration
Piping and Instrumentation Diagrams (P&ID) show the process, additional
information is needed for the specification of the Process Control and Safety
Systems.
The illustration shows one typical format common format for the Norwegian
offshore industry: The Njård Separator 1 and 2 Systems Control Diagram (SCD.
Essentially, the P&ID mechanical information has been removed, and control loops
and safety interlocks drawn in with references to typical loops.
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5.1.4 Fire and Gas Systems
The Fire and Gas System is not generally related to any particular process. Instead it
divides into fire areas by geographical location. Each fire area should be designed to
be self contained, in that it should detect fire and gas by several types of sensors, and
control fire protection and fire fighting devices to contain and fight fire within the
fire area. In case of fire, the area will be partially shut off by closing ventilation fire
dampers. A fire area protection data
sheet typically shows what detection
exists for each fire area and what fire
protection action should be taken in
case of an undesirable event.
A separate package related to fire and
gas is the diesel or electrically driven
fire water pumps for the sprinkler and
deluge ring systems. The type and
number of the detection, protection
and fighting devices depend on the
type of equipment and size of the fire
area and is different for e.g. process
areas, electrical rooms and
accommodations.
Fire detection:
- Gas detection: Combustible and Toxic gas, Electro catalytic or optical
(IR) detector.
- Flame detection: Ultraviolet (UV) or Infra Red (IR) optical detectors
- Fire detection: Heat and Ionic smoke detectors
- Manual pushbuttons
Firefighting, protection:
- Gas based fire-fighting such as CO2
- Foam based fire-fighting
- Water based fire-fighting: Sprinklers, Mist (Water spray) and deluge
- Protection: Interface to emergency shutdown and HVAC fire dampers.
- Warning and escape: PA systems, beacons/lights, fire door and damper
release
For detection, coincidence and voting is often used to false alarms. In such schemes,
it is required that several detectors in the same area detect a fire condition or gas
leakage for automatic reaction. This will include different detection principles e.g. to
trig on fire but not welding or lightening.
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Action is controlled by a fire and
gas system. Like the ESD
system, F&G action is specified
in a cause and action chart called
the Fire Area Protection
Datasheet. This chart shows all
detectors and fire protection
systems in a fire area and how
the system will operate.
The F&G system often provides
supervisory functions, either in
the F&G or the PIMS to handle
such tasks as maintenance,
calibration, replacement and hot
work permits e.g. welding. Such
action may require that one or
more Fire and Gas detectors or
systems are overridden or
bypassed. Specific work
procedures should be enforced,
such as a placing fire guards on
duty and make sure all devices
are re-enabled when the work
permit expires or work is
complete.
5.1.5 Telemetry / SCADA
SCADA (Supervisory Control and Data Acquisition) is normally associated with
telemetry and wide area communications, for data gathering and control over large
production sites, pipelines, or corporate data from multiple facilities. With telemetry,
the bandwidth is often quite low and based on telephone or local radio systems the
SCADA system is often optimized for efficient use of the available bandwidth. Wide
area communication operates with wideband services, such as optical fibers and
broadband internet.
Remote Terminal Units (RTU) or local controls systems on wells, wellhead
platforms, compressor and pump stations are connected to the SCADA system by
mean dot the available communication media. SCADA systems have many of the
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same functions as the control system, and the difference mainly comes down to data
architecture and use of communications.
5.1.6 Condition Monitoring and Maintenance Support
Condition monitoring encompasses both structural monitoring and condition
monitoring for process equipment such as valves and rotating machinery.
For structural monitoring, the devices are corrosion meters (essentially plates that
corrode, and where that corrosion may be metered), tension force meters and free
swinging strings. These are logged to a central structure condition monitoring
system, to portray the forces acting on the installation, and the effect those forces are
having.
Condition monitoring of machinery is generally used for large rotating apparatus,
such as turbines, compressors, generators and large pumps. Input devices are
vibration meters, temperature (bearing, exhaust gases etc.) as well as number of
start/stops, running time, lubrication intervals and over-current trips. These values
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are logged and compared with reference values to detect abnormal conditions and
indicate when preventive maintenance is required or an equipment fault occurs (i.e.
maintenance triggers)
For other process equipment such as valves the system can register closing times,
flow and torque. A valve which exhibits a negative trend in closing time or torque
(“sticktion”) can be diagnosed. Generally “maintenances triggers” are based on
equipment diagnostics to predict when preventive maintenance is required. Fieldbus
mounted transmitters and actuators are particularly well suited to condition
monitoring diagnostics.
Maintenance support functionality will plan maintenance based on input from
condition monitoring systems and a periodic maintenance plant. This will allow the
system to schedule personnel for such tasks as lubrication or cleaning, and plan
larger tasks such as turbine and compressor periodic maintenance.
5.1.7 Production Information Management Systems
(PIMS)
A specific information management system
can be used to provide information about the
operation and production of the facility. This
can be a separate system, or an integral part of
the control system or SCADA system.
For Oil and Gas, PIMS functionality includes:
• Oil & Gas Production Reporting.
• Safety Management
• Maintenance
• Operator Support
• Overall systems integration and
external
• Historical data including post failure “flight recorder” data
Some of the application provided by a PIMS system may be:
• Well Test application.
• Production Allocation (oil/gas/water) based on Well Test results.
• Metering data from integrated metering system.
• Volume in storage cells & consolidation of produced stored and dispatched
volumes.
• Safety data, alarms & operators comments.
• Drilling data acquisition and drilling data logging
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• Safety report, including shutdown analysis
• Operation logs
• Operator Procedures
• Laboratory data & data from administrative systems.
5.1.8 Training Simulators
Training Simulators are used to
provide realistic operator training
in a realistic plant training
environment. Training simulators
uses the actual control and safety
applications of the plant, running in
operator stations. Plant models
simulate the feedback from the
plant in real time or fast/slow
motion. The training simulator
applications include functions for
backup and reload including
recreation of historical information and snapshots. Offsite training facilities are often
connected (read only) to the live plant to give information from the real operating
situation.
5.2 Power generation and distribution
Power can be provided from mains power or from local diesel generator sets. Large
facilities have great power demands, from 30 MW and upwards to several hundred
MW. There is a tendency to generate electric power centrally and use electric drives
for large equipment rather than multiple gas turbines, as this decreases maintenance
and increases uptime.
The power generation system on a large
facility is usually several gas turbines diving
electric generators, 20-40 MW each. If
exhaust heat is not needed in the main process,
it can be used to drive exhaust steam turbines
(so called dual cycle) for additional efficiency.
Voltage levels for High, Medium and Low
voltage distribution boards are 13- 130kV, 2-8
kV and 300-600 V respectively. Power is
generated and exchanged with mains or other
facilities on the HV distribution board. Relays
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are used for protection functions
HV is transformed to MV switchboards where large consumers are connected. The
LV switchboards feed a mix of normal consumers, Motor Control centers and
variable speed drives for motors up to a few hundred KW (Not necessarily separate
as shown in the figure).
A separate emergency power switchboard provides power for critical equipment. It
can be powered from a local emergency generator if main power is lost. Computer
systems are fed from an Uninterruptible Power System (UPS) connected to the
emergency switchboard and/or a battery bank.
A power management system is used for control of electrical switchgear and
equipment. Its function is to optimize electricity generation and usage and to prevent
major disturbances & plant outages (blackouts). The power management system
includes HV, MV and LV low voltage switchgear as well as Motor Control Centers
(MCC) and emergency generator sets. Functions include prioritization of loads,
emergency load shedding (closing down of non-essential equipment) and prestart of
generator sets (e.g. when additional power to start a big crude pump is required)
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Large rotating equipment and the generators are driven by gas turbines or large
drives. Gas turbines for oil and gas duty are generally modified aviation turbines in
the 10-25 MW range. These require quite extensive maintenance and have a
relatively low overall
efficiency (20-27% depending
on application). Also, while
the turbine is relatively small
and light, it will usually
require large and heavy
support equipment such as
large gears, air coolers/filters,
exhaust units, sound damping
and lubrication units.
Therefore use of large variable
speed drives is becoming more
common. For pumps on
Subsea facilities this is the only option. For use on remote facilities, High Voltage
DC transmission and HV motors can be used, from a main facility or power from
shore. This will also avoid local power generation at each facility and contribute to
low manning or remote operation.
5.3 Flare and Atmospheric Ventilation
The flare subsystem include Flare,
atmospheric ventilation and blow down. The
purpose of the Flare and Vent Systems is to
provide safe discharge and disposal of gases
and liquids resulting from:
• Spill-off flaring from the product
stabilisation system. (Oil, Condensate
etc.).
• Production testing
• Relief of excess pressure caused by
process upset conditions and thermal
expansion.
• Depressurisation either in response to
an emergency situation or as part of a
normal procedure.
• Planned depressurisation of subsea production flowlines and export
pipelines.
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• Venting from equipment operating close to atmospheric pressure (e.g.
Tanks)
The systems are typically divided into a High Pressure (HP) Flare and a Low
Pressure (LP) flare system. The LP system is operated marginally above atmospheric
pressure to prevent atmospheric gases such as Oxygen to flow back into the vent and
flare system and greate a combustible mixture. With low gas flow, inert gas is
injected at the flare nozzle to prevent air ingress.
Traditionally, considerable amounts of hydrocarbons have been more or less
continuously flared. In these cases, a contiuously burning pilot is used to ensure
ignition of hydrocarbons in the flare.
Stronger environmental focus has elimintated continuous flaring and the pilot in
many areas. Vapors and flare gas are normally recovered, and only in exceptional
situations does flaring occur. To avoid the pilot flame, an ignition system is used to
ensure safe ignition even when large volumes are discharged. One patented solution
is a “ballistic ignition” system which fires burning pellets into the flare gas flow.
5.4 Instrument air
A large volume of compressed air is required for the control of pneumatic valves and
actuators, tools and purging of cabinets. It is produced by electrically driven screw
compressors and further treated to be free of particles, oil and water
5.5 HVAC
The heat, ventilation and air conditioning system (HVAC) feeds conditioned air to
the equipment rooms, accommodations etc. Cooling and heating is achieved by way
of water cooled or water/steam heated heat exchangers. Heat may also be taken off
gas turbine exhaust. In tropic and sub-tropic areas, the cooling is achieved by
compressor refrigeration units. Also, in tropical areas gas turbine inlet air must be
cooled to achieve sufficient efficiency and performance. The HVAC system is
usually delivered as one package, and may also include air emissions cleaning. Some
HVAC subsystems include:
• Cool: Cooling Medium, Refrigation System, Freezing System
• Heat: Heat medium system, Hot Oil System.
One function is to provide air to equipment rooms that are safe by positive pressure.
This prevents potential influx of explosive gases in case of a leak.
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5.6 Water Systems
5.6.1 Potable Water
For smaller installations potable water can be transported in by supply vessels or
tank trucks.
For larger facilities,
potable water is
provided on site by
desalination of seawater
though distillation or
reverse osmosis.
Onshore potable water
is provided by
purification of water
from above ground or
underground reservoirs.
Reverse osmosis requires a membrane driving pressure of about 7000 kPa / 1 PSI of
pressure per 100 ppm of solids dissolved in the water. For seawater with 3,5 % salt,
2,5 MPa, 350 PSI is required. Photo: Lenntech Water treatment & air purification Holding B.V.
5.6.2 Seawater
Seawater is used extensively for cooling purposes. Cooling water is provided to Air
Compressor Coolers, Gas Coolers, Main Generators and HVAC. In addition
seawater is used for production of hypochlorite (see chemicals) and for Fire Water.
Seawater is treated with hypochlorite to prevent microbiological growth in process
equipment and piping.
Seawater is sometimes used for reservoir water injection. In this case a deaerator is
used to reduce oxygen in the water before injection. Oxygen can cause
microbiological growth in the reservoir. The deaerator is designed to use strip gas
and vacuum.
5.6.3 Ballast Water
Ballast systems are found on drilling rigs, floating production ships and rigs as well
as TLP (tension leg platforms). The object is to keep the platform level and at a
certain depth under varying conditions, such as mode of operation (stationary
drilling, movement), climatic conditions (elevate rig during storms), amount of
produce in storage tanks, and to adjust loading on TLP tension members.
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The ballasting is accomplished by way of ballast tanks, pumps and valves, which are
used in combination with position measuring instruments and tension force meters
(TLP) to achieve the desired ballasting.
Produced water, if available can be used as ballast to avoid salt water. Additionally,
if ballast water has become contaminated from oil tanks, it must be cleaned before
discharge to sea.
5.7 Chemicals and Additives
A wide range of chemical additives are
used in the main process. Some of these
are marked in the process diagram. The
cost of process chemical additives is
considerable. A typical example is
antifoam where a concentration of about
150 ppm is used. With a production of
40.000 bpd, about 2000 litres (500
Gallons) of antifoam could be used. At a
cost of 2 /liter, 10 $/Gallon in bulk, just
the antifoam will cost some 4000 Euro /
5000 USD per day.
The most common chemical s and their uses are:
Scale inhibitor
Emulsion breaker
The well flow contains several different contaminants such
as salts, chalk, and traces of radioactive materials. As
pressure and temperature changes, these may precipitate and
deposit in pipes, heat exchangers, valves and tanks. As a
result these may clog up or become stuck. The scale
inhibitor will prevent the contaminants from separating out.
Scale or sediment inhibitor is added on wellheads and
production equipment.
Water and Oil cannot mix to form a solution. However
small drops of oil will disperse in water and small water
drops will disperse in oil. These drops are held suspended
by attractive and repulsive electrostatic forces at the
molecular level. This is called an emulsion and will form a
layer between the oil and water. Although the emulsion
layer will eventually break down naturally, it prevents full
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Antifoam
Polyelectrolyte
Methanol (MEG)
TEG
separation in reasonable time. An emulsion breaker is added
to prevent formation of, and break down of the emulsion
layer by causing the droplets to merge and grow. Sand and
particles will normally be carried out by the water and be
extracted in water treatment. However, the emulsion can
trap these particles and sink to the bottom as a viscous
sludge that is difficult to remove during operation.
The sloshing motion inside a separator will cause foaming.
The foam will cover the fluid surface and prevent gas to
escape. Also, the foam reduces the gas space inside the
separator, and worst case it will pass the demister and
escape to the gas outlet as mist and liquid drops. An
antifoam agent is introduced upstream of the separator to
prevent or break down foam formation, by reducing liquid
surface tension.
Polyelectrolyte is added before the hydrocyclones and
causes oil droplets to merge. Works by reducing surface
tension and water polarity. This is also called flocculation
and polyelectrolyte flocculants and allows emissions to
reach 40 ppm or less.
Methanol or Mono Ethylene Glycol (MEG) is injected in
flowlines to prevent Hydrate formation and prevent
corrosion. Hydrates are crystalline compounds that form in
water crystalline structures as a function of composition,
temperature and pressure. Hydrates form and freeze to
hydrate ice that may damage equipment and pipelines.
For normal risers, hydrates form only when production stops
and the temperature start to drop. Hydrate formation can be
prevented by depressurization which adds to startup time or
by Methanoli injection.
On longer flowlines in cold seawater or arctic climates,
hydrates may form under normal operating conditions and
require continuous methanol injection. In this case the
methanol can be separated and recycled.
Hydrate prediction model software can be used to determine
when there is a risk for hydrate formation and to reduce
methanol injection or delay depressurization.
Tri Ethylene Glycol (TEG) is used to dry gas. See scrubbers
and reboilers chapter.
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Hypochlorite
Biocides
Hypochlorite is added to seawater to prevent growth of
algae and bacteria e.g. in seawater heat exchangers.
Hypochlorite is produced by electrolysis of seawater to
chlorine. In one variant, copper electrodes are used which
adds copper salts to the solution which improves
effectiveness.
Biocides are also preventive chemicals that are added to
prevent microbiological activity in oil production systems
such as bacteria, fungus or algae growth. Particular
problems arise from growth of sulfate bacteria that produces
hydrogen sulfide and clogs filters. Typical uses include
diesel tanks, produced water (after hydrocyclones), and slop
and ballast tanks.
Corrosion Inhibitor is injected in the export pipelines and storage tanks. Exported
oil could be very corrosive and lead to corrosion of the
inside of the pipeline or tank. The corrosion inhibitor will
protect by forming a thin film on the metal surface.
Drag Reducers
Drag reducers improve flow in pipelines. Fluid near the pipe
tries to stay stationary while fluid in the center region of the
pipe is moving quickly. This large difference in fluid causes
turbulent bursts to occur in the buffer region. Turbulent
bursts propagate and form turbulent eddies, which cause
drag. Drag-reducing polymers are long-chain, ultra-high
molecular weight polymers from 1 to 10 million u), with
higher molecular weight polymers giving better drag
reduction performance. With only parts-per-million levels in
the pipeline fluid, drag-reducing polymers suppress the
formation of turbulent bursts in the buffer region. The net
result of using a drag-reducing polymer in turbulent flow is
a decrease in the frictional pressure drop in the pipeline by
as much as 70%. This can be used to lower pressure or
improve throughput.
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5.8 Telecom
The telecom system consists of variety of subsystems for human and computer wired
and wireless communications, monitoring, observation and entertainment: Some of
the main systems are:
• Public Address & Alarm System/F&G Integration
• Drillers talk back System
• UHF Radio Network System
• Closed Circuit TV System
• Mandatory Radio System
• Security Access Control
• Meteorological System/Sea Wave Radar
• Telecom Antenna Tower and Antennas
• PABX Telephone System
• Entertainment System
• Marine Radar & Vessel Movement System
• Office Data Network and Computer System
• Personnel Paging System
• Platform Personnel Registration and Tracking System
• Telecom Maintenance and Monitoring System
• Ship Communication System/PABX Extension
• Radio Link Backup System
• Mux and Fiber optical Terminal Equipment
77

6 Units
Some common units used in the oil and gas industry. I have listed a representative
selection of US and metric units since both are used in different parts of the oil
industry. The non standard factors differ slightly between different sources.
API American Petroleum
Institute crude grade
API = (141.5 / Specific gravity ) + 131,5
Spec gravity = 141.5/(API + 131,5) kg/l
Bl Barrel (of oil) 1 Bl = 42 Gallons
1 Bl = 159 liters
1 Bl equiv. to 5487 scf = 147 scm gas
Bpd Barrel per day 1 Bpd 50 tons/tonnes per year
BTU British Thermal Unit 1 BTU = 0,293 Wh = 1,055 kJ
CO2
CO2 emissions from
hydrocarbons
Typical values
1,625 Ton CO2 per Ton gas (for CH4)
1,84 Ton CO2 per Ton Crude Oil
0,94 kg per scm gas
Cal Calorie 1 Cal = 4,187 J (Joules)
MMscf Million Standard Cubic 1 MMscf = 23.8 TOE 174 barrels
Feet
psi Pounds Per Square 1 psi = 6,9 kPa = 0,069 atm
Inch
Scf Standard Cubic Feet
(of gas) Defined by
energy not a normalized
volume
1 scf = 1000 BTU = 252 kcal
= 293 Wh = 1,055 MJ
0.0268 scm
Scm
TOE
kWh
Standard Cubic metre
(of gas, also Ncm)
Defined by energy
content
Tons oil equivalent
Range 6.6 - 8 barrels at
API range 8 - 52
kiloWatthour
= 1000 Joules * 3600 S
1 Scm = 39 MJ = 10.8 kWh
1 Scm 37,33 Scf (not a volume conv.)
1 Scm 1,122 kg
1 TOE = 1 kilograms = 1 Ton (metric) oil
1 TOE = 1 Tonne oil (US)
1 TOE 7,33 Barrels (at 33 API)
1 TOE 42,9 GJ =11,9 MWh
1 TOE 40,6 MMBTU
1 TOE 1,51 ton of coal
1 TOE 0,79 ton LNG
1 TOE 1125 Scm = 42000 Scf
1 kWh = 3,6 MJ = 860 kcal = 3413 BTU
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Product specific gravity, API grades
Product
Liters Per Ton
(metric)
API
Grade
Specific
Gravity
(kg/m3)
Barrels per
Ton
At 60°F
LPG 1835 10 1000 6,29
Jet A-1 1254 18 934 6,73
Gasoline
1353 25 904 6,98
premium/super
Gasoline regular 1418 30 876 7,19
Kerosene 1273 33 860 7,33
Gas Oil 1177 36 845 7,46
Diesel Fuel 1159 39 830 7,60
Fuel oil 80 CST 1065 42 816 7,73
Fuel oil 180 CST 1050 50 780 8,06
Fuel oil 230 CST 1047
Fuel oil 280 CST 1044
Bitumen 979
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7 Acronyms
Acronym Description
AC
Alternating Current
AGA
American Gas Association
API
American Petroleum Institute
CCR
Central Control Room
CMS
Condition Monitoring Systems
CSP
Collector and Separation Platform
DC
Direct Current
DYNPOS Dynamic positioning (of rigs and ships)
E&P
Exploration and Production
EOR
Enhanced Oil Recovery
ESD
Emergency ShutDown system
ESP
Electric Submerged Pump
F&G
Fire & Gas System
FPSO
Floating Production Storage and Offloading
GB(S)
Gravity Base Structure
GOR
Gas Oil Ratio from the well
GOSP
Gas Oil Separation Plant
GTP
Gas Treatment Platform
HP
High Pressure
HPU
Hydraulic Power Unit (topside utility for subsea)
HVAC
Heat Ventilation and Air Conditioning
IR
Infra Red
ISO
International Standards Organization
K-Mass Flow Coriolis type Mass Flow meter
LNG
Liquid Natural Gas (e.g. Metane)
LP
Low Pressure
LPG
Liquified Petroleum Gas (e.g. Propane)
MCC
Motor Control Centre
MTBF
Mean Time Between Failure
NGL
Natural Gas Liquids, Condensates see also LPG
PCP
Progressive Cavity Pump
PD-Meter Positive Displacement meter
PGP
Power Generation Platform
PID
Proportional Integral Derivate control algorithm
PIMS
Production Information Management System
PoC
Pimp of controller (for articifial lift)
POSMOR Position mooring for a floating facility
PSD
Process Shutdown System
ROV
Remote Operated Vehicle (for subsea workover)
RTU
Remote Terminal Unit
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SAS
Safety and Automation System
SCADA
Supervisory Control And Data Acquisition
TIP
Tie-In Platform
TLP
Tension Leg Platform
UMS Unmanned Machinery Space classification (marine =
E0)
URF
Umbilicals, Risers and Flowlines
UV
Ultra Violet
WHP
Well Head Platform
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8 References
Web on line sources and references that has been used in compiling this document:
• Schlumberger oilfield glossary:
http://www.glossary.oilfield.slb.com/default.cfm
• Norsk Hydro, Njord Main Process and Oil Process Description.
http://www.hydro.com/en/our_business/oil_energy/production/oil_gas_nor
way/njord.html
• Wikipedia http://en.wikipedia.org/wiki/Main_Page
• Oklahoma State, Marginal Well Commission, Pumper’s Manual
http://www.marginalwells.com/MWC/pumper_manual.htm
• Natural Gas Supply Association. See Natural Gas - From Wellhead to
Burner Tip
http://www.naturalgas.org/index.asp
• US geological survey: http://www.usgs.gov/
• US departmen of energy: http://www.doe.gov/
• NORSOK standards, Standards Norway (SN),
http://www.standard.no/imaker.exe?id=244
• UK Offshore Operators Association (UKOOA)
http://www.oilandgas.org.uk/issues/storyofoil/index.htm
• National Biodiesel Board http://www.biodiesel.org/
• PBS – Public Broadcasting Service - Extreme Oil
http://www.pbs.org/wnet/extremeoil/index.html
• http://www.priweb.org/ed/pgws/history/pennsylvania/pennsylvania.html
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